HAWAIIAN ELECTRIC CO INC - Quarter Report: 2006 March (Form 10-Q)

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 March 31, 2006

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


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

and Principal Subsidiary

HAWAIIAN ELECTRIC COMPANY, INC.	1-4955	99-0040500

State of Hawaii

(State or other jurisdiction of incorporation or organization)

900 Richards Street, Honolulu, Hawaii 96813

(Address of principal executive offices and zip code)

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

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

(Registrant’s telephone number, including area code)

Not applicable

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

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

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

Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc. is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer x

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

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

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 May 1, 2006
Hawaiian Electric Industries, Inc. (Without Par Value)		81,120,692 Shares
Hawaiian Electric Company, Inc. ($6-2/3 Par Value)		12,805,843 Shares (not publicly traded)

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended March 31, 2006

INDEX


		Page No.
Glossary of Terms		ii
Forward-Looking Statements		iv

PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements

	Hawaiian Electric Industries, Inc. and Subsidiaries

	Consolidated Balance Sheets (unaudited) - March 31, 2006 and December 31, 2005	1

	Consolidated Statements of Income (unaudited) - three months ended March 31, 2006 and 2005	2

	Consolidated Statements of Changes in Stockholders’ Equity (unaudited) -three months ended March 31, 2006 and 2005	3

	Consolidated Statements of Cash Flows (unaudited) - three months ended March 31, 2006 and 2005	4

	Notes to Consolidated Financial Statements (unaudited)	5

	Hawaiian Electric Company, Inc. and Subsidiaries

	Consolidated Balance Sheets (unaudited) - March 31, 2006 and December 31, 2005	14

	Consolidated Statements of Income (unaudited) -three months ended March 31, 2006 and 2005	15

	Consolidated Statements of Retained Earnings (unaudited) -three months ended March 31, 2006 and 2005	15

	Consolidated Statements of Cash Flows (unaudited) -three months ended March 31, 2006 and 2005	16

	Notes to Consolidated Financial Statements (unaudited)	17

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32

	HEI Consolidated	32

	Electric Utilities	36

	Bank	48

	Certain Factors that May Affect Future Results and Financial Condition	51

	Material Estimates and Critical Accounting Policies	51

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	52

Item 4.	Controls and Procedures	53

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	53

Item 1A.	Risk Factors	53

Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	54

Item 5.	Other Information	54

Item 6.	Exhibits	55

Signatures		56

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended March 31, 2006

GLOSSARY OF TERMS


Terms		Definitions

AFUDC		Allowance for funds used during construction

AOCI		Accumulated other comprehensive income

ASB		American Savings Bank, F.S.B., a wholly-owned subsidiary of HEI Diversified, Inc. and parent company of American Savings Investment Services Corp. (and its subsidiary, Bishop Insurance Agency of Hawaii, Inc.) and AdCommunications, Inc. Former subsidiaries include ASB Realty Corporation (dissolved in May 2005).

BLNR		Board of Land and Natural Resources of the State of Hawaii

CHP		Combined heat and power

Company		Hawaiian Electric Industries, Inc. and its direct and indirect subsidiaries, including, without limitation, Hawaiian Electric Company, Inc., Maui Electric Company, Limited, Hawaii Electric Light Company, Inc., HECO Capital Trust III, Renewable Hawaii, Inc., HEI Diversified, Inc., American Savings Bank, F.S.B. and its subsidiaries, Pacific Energy Conservation Services, Inc., HEI Properties, Inc., Hycap Management, Inc. (in dissolution), Hawaiian Electric Industries Capital Trust II, Hawaiian Electric Industries Capital Trust III, The Old Oahu Tug Service, Inc. and HEI Power Corp. and its subsidiaries (discontinued operations, except for subsidiary HEI Investments, Inc.). (unconsolidated subsidiaries)

Consumer Advocate		Division of Consumer Advocacy, Department of Commerce and Consumer Affairs of the State of Hawaii

D&O		Decision and order

DG		Distributed generation

DOD		Department of Defense — federal

DOH		Department of Health of the State of Hawaii

DRIP		HEI Dividend Reinvestment and Stock Purchase Plan

DSM		Demand-side management

EITF		Emerging Issues Task Force

EPA		Environmental Protection Agency — federal

Exchange Act		Securities Exchange Act of 1934

FASB		Financial Accounting Standards Board

Federal		U.S. Government

FHLB		Federal Home Loan Bank

FIN		Financial Accounting Standards Board Interpretation No.

GAAP		Accounting principles generally accepted in the United States of America

HECO		Hawaiian Electric Company, Inc., an electric utility subsidiary of Hawaiian Electric Industries, Inc. and parent company of Maui Electric Company, Limited, Hawaii Electric Light Company, Inc., HECO Capital Trust III (unconsolidated subsidiary) and Renewable Hawaii, Inc.

GLOSSARY OF TERMS, continued


Terms		Definitions

HEI		Hawaiian Electric Industries, Inc., direct parent company of Hawaiian Electric Company, Inc., HEI Diversified, Inc., Pacific Energy Conservation Services, Inc., HEI Properties, Inc., Hycap Management, Inc. (in dissolution), Hawaiian Electric Industries Capital Trust II, Hawaiian Electric Industries Capital Trust III, The Old Oahu Tug Service, Inc. and HEI Power Corp. (discontinued operations, except for subsidiary HEI Investments, Inc.). (*unconsolidated subsidiaries)

HEIDI		HEI Diversified, Inc., a wholly owned subsidiary of Hawaiian Electric Industries, Inc. and the parent company of American Savings Bank, F.S.B.

HEIII		HEI Investments, Inc. (formerly HEI Investment Corp.), a subsidiary of HEI Power Corp.

HEIPC		HEI Power Corp., a wholly owned subsidiary of Hawaiian Electric Industries, Inc., and the parent company of numerous subsidiaries, the majority of which were dissolved or otherwise wound up since 2002, pursuant to a formal plan to exit the international power business (formerly engaged in by HEIPC and its subsidiaries) adopted by the HEI Board of Directors in October 2001

HEIPC Group		HEI Power Corp. and its subsidiaries

HEIRSP		Hawaiian Electric Industries Retirement Savings Plan

HELCO		Hawaii Electric Light Company, Inc., an electric utility subsidiary of Hawaiian Electric Company, Inc.

IPP		Independent power producer

IRP		Integrated resource plan

KWH		Kilowatthour

MECO		Maui Electric Company, Limited, an electric utility subsidiary of Hawaiian Electric Company, Inc.

MW		Megawatt/s (as applicable)

NII		Net interest income

NPV		Net portfolio value

PPA		Power purchase agreement

PRPs		Potentially responsible parties

PUC		Public Utilities Commission of the State of Hawaii

RHI		Renewable Hawaii, Inc., a wholly owned subsidiary of Hawaiian Electric Company, Inc.

ROACE		Return on average common equity

ROR		Return on average rate base

SEC		Securities and Exchange Commission

See		Means the referenced material is incorporated by reference

SFAS		Statement of Financial Accounting Standards

SOIP		1987 Stock Option and Incentive Plan, as amended

SOX		Sarbanes-Oxley Act of 2002

SPRBs		Special Purpose Revenue Bonds

TOOTS		The Old Oahu Tug Service, a wholly owned subsidiary of Hawaiian Electric Industries, Inc.

VIE		Variable interest entity

iii

Forward-Looking Statements

This report and other presentations made by Hawaiian Electric Industries, Inc. (HEI) and Hawaiian Electric Company, Inc. (HECO) and their subsidiaries contain “forward-looking statements,” which include statements that are predictive in nature, depend upon or refer to future events or conditions, and usually include words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “predicts,” “estimates” or similar expressions. In addition, any statements concerning future financial performance, ongoing business strategies or prospects and 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 in forward-looking statements and from historical results include, but are not limited to, the following:

•

the effects of international, national and local economic conditions, including the state of the Hawaii tourist and construction industries, the strength or weakness of the Hawaii and continental U.S. real estate markets (including the fair value of collateral underlying loans and mortgage-related securities) and decisions concerning the extent of the presence of the federal government and military in Hawaii;

•

the effects of weather and natural disasters;

•

global developments, including the effects of terrorist acts, the war on terrorism, continuing U.S. presence in Iraq and Afghanistan, potential conflict or crisis with North Korea, relations with Iran and Iran’s nuclear activities;

•

the timing and extent of changes in interest rates;

•

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

•

changes in assumptions used to calculate retirement benefits costs and changes in funding requirements;

•

demand for services and market acceptance risks;

•

increasing competition in the electric utility and banking industries (e.g., increased self-generation of electricity may have an adverse impact on HECO’s revenues and increased price competition for deposits, or an outflow of deposits to alternative investments, may have an adverse impact on American Savings Bank, F.S.B.’s (ASB’s) cost of funds);

•

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

•

increased risk to generation reliability as generation reserve margins on Oahu are lower than considered desirable;

•

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;

•

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 and its subsidiaries) or their competitors;

•

federal, state and international governmental and regulatory actions, such as changes in laws, rules and regulations applicable to HEI, HECO and their subsidiaries (including changes in taxation, environmental laws and regulations and governmental fees and assessments); decisions by the Public Utilities Commission of the State of Hawaii (PUC) in rate cases and other proceedings and by other agencies and courts on land use, environmental and other permitting issues; required corrective actions, restrictions and penalties (that may arise with respect to environmental conditions, capital adequacy and business practices);

•

increasing operations and maintenance expenses for the electric utilities and the possibility of more frequent rate cases;

•

the risks associated with the geographic concentration of HEI’s businesses;

•

the effects of changes in accounting principles applicable to HEI, HECO and their subsidiaries, including continued regulatory accounting under Statement of Financial Accounting Standards (SFAS) No. 71 (Accounting for the Effects of Certain Types of Regulation), the possible effects of applying Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46R (Consolidation of Variable Interest Entities) and Emerging Issues Task Force (EITF) Issue No. 01-8 (Determining Whether an Arrangement Contains a Lease) to power purchase arrangements with independent power producers, and the possible effects of potential changes in the accounting for retirement benefits;

•

the effects of 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 rights 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;

•

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

•

the ability of consolidated HEI to generate capital gains and utilize capital loss carryforwards on future tax returns;

•

the risks of suffering losses and incurring liabilities that are uninsured; and

•

other risks or uncertainties described elsewhere in this report and in other periodic 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 and its subsidiaries undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)


(dollars in thousands)	March 31, 2006			December 31, 2005
Assets
Cash and equivalents	$	155,382		$	151,513
Federal funds sold		85,232			57,434
Accounts receivable and unbilled revenues, net		228,771			249,473
Available-for-sale investment and mortgage-related securities		2,609,160			2,629,351
Investment in stock of Federal Home Loan Bank of Seattle, at cost		97,764			97,764
Loans receivable, net		3,618,246			3,566,834
Property, plant and equipment, net of accumulated depreciation of $1,567,621 and $1,538,836		2,558,800			2,542,776
Regulatory assets		111,438			110,718
Other		425,892			456,134
Goodwill and other intangibles, net		89,023			89,580

	$	9,979,708		$	9,951,577

Liabilities and stockholders’ equity
Liabilities
Accounts payable	$	183,852		$	183,336
Deposit liabilities		4,610,399			4,557,419
Short-term borrowings		182,584			141,758
Other borrowings		1,623,287			1,622,294
Long-term debt, net		1,133,041			1,142,993
Deferred income taxes		195,874			207,997
Regulatory liabilities		224,598			219,204
Contributions in aid of construction		260,692			256,263
Other		319,566			369,390

		8,733,893			8,700,654

Minority interests
Preferred stock of subsidiaries—not subject to mandatory redemption		34,293			34,293

Stockholders’ equity
Preferred stock, no par value, authorized 10,000,000 shares; issued: none		—			—
Common stock, no par value, authorized 100,000,000 shares; issued and outstanding: 81,059,892 shares and 80,983,326 shares		1,020,161			1,018,966
Retained earnings		242,605			235,394
Accumulated other comprehensive loss, net of tax benefits		(51,244	)		(37,730	)

		1,211,522			1,216,630

	$	9,979,708		$	9,951,577

See accompanying “Notes to Consolidated Financial Statements” for HEI.

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)


(in thousands, except per share amounts and ratio of earnings to fixed charges)	Three months ended March 31
	2006			2005
Revenues
Electric utility	$	475,056		$	374,775
Bank		100,004			97,224
Other		(98	)		629

		574,962			472,628

Expenses
Electric utility		429,476			343,169
Bank		72,989			68,271
Other		3,346			4,517

		505,811			415,957

Operating income (loss)
Electric utility		45,580			31,606
Bank		27,015			28,953
Other		(3,444	)		(3,888	)

		69,151			56,671

Interest expense—other than bank		(19,117	)		(18,835	)
Allowance for borrowed funds used during construction		702			427
Preferred stock dividends of subsidiaries		(473	)		(476	)
Allowance for equity funds used during construction		1,548			1,087

Income before income taxes		51,811			38,874
Income taxes		19,474			14,779

Net income	$	32,337		$	24,095

Basic earnings per common share	$	0.40		$	0.30

Diluted earnings per common share	$	0.40		$	0.30

Dividends per common share	$	0.31		$	0.31

Weighted-average number of common shares outstanding		80,981			80,701
Dilutive effect of stock-based compensation		382			434

Adjusted weighted-average shares		81,363			81,135

Ratio of earnings to fixed charges (SEC method)
Excluding interest on ASB deposits		2.33			2.00

Including interest on ASB deposits		1.95			1.76

See accompanying “Notes to Consolidated Financial Statements” for HEI.

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Changes in Stockholders’ Equity (unaudited)


	Common stock			Retained earnings			Accumulated other comprehensive loss			Total
(in thousands, except per share amounts)	Shares	Amount		Retained earnings			Accumulated other comprehensive loss			Total
Balance, December 31, 2005	80,983	$	1,018,966	$	235,394		$	(37,730	)	$	1,216,630
Comprehensive income:
Net income	—		—		32,337			—			32,337
Net unrealized losses on securities arising during the period, net of tax benefits of $8,890	—		—		—			(13,466	)		(13,466	)
Minimum pension liability adjustment, net of tax benefits of $30	—		—		—			(48	)		(48	)

Comprehensive income (loss)	—		—		32,337			(13,514	)		18,823

Issuance of common stock, net	77		1,195		—			—			1,195
Common stock dividends ($0.31 per share)	—		—		(25,126	)		—			(25,126	)

Balance, March 31, 2006	81,060	$	1,020,161	$	242,605		$	(51,244	)	$	1,211,522

Balance, December 31, 2004	80,687	$	1,010,090	$	208,998		$	(8,143	)	$	1,210,945
Comprehensive income:
Net income	—		—		24,095			—			24,095
Net unrealized losses on securities arising during the period, net of tax benefits of $13,179	—		—		—			(28,661	)		(28,661	)

Comprehensive income (loss)	—		—		24,095			(28,661	)		(4,566	)

Issuance of common stock, net	25		1,914		—			—			1,914
Common stock dividends ($0.31 per share)	—		—		(25,020	)		—			(25,020	)

Balance, March 31, 2005	80,712	$	1,012,004	$	208,073		$	(36,804	)	$	1,183,273

See accompanying “Notes to Consolidated Financial Statements” for HEI.

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)


	Three months ended March 31
(in thousands)	2006			2005
Cash flows from operating activities
Net income	$	32,337		$	24,095
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment		35,261			33,505
Other amortization		2,196			(2	)
Reversal of allowance for loan losses		—			(3,100	)
Deferred income taxes		(2,839	)		(1,593	)
Allowance for equity funds used during construction		(1,548	)		(1,087	)
Excess tax benefits from share-based payment arrangements		(316	)		—
Changes in assets and liabilities, net of effects from the disposal of businesses
Decrease in accounts receivable and unbilled revenues, net		20,702			26,588
Decrease in federal tax deposit		30,000			—
Increase in accounts payable		516			14,144
Decrease in taxes accrued		(36,217	)		(22,356	)
Changes in other assets and liabilities		(9,293	)		(22,680	)

Net cash provided by operating activities		70,799			47,514

Cash flows from investing activities
Available-for-sale investment and mortgage-related securities purchased		(125,000	)		(50,006	)
Principal repayments on available-for-sale mortgage-related securities		121,632			169,580
Net increase in loans held for investment		(58,078	)		(81,887	)
Capital expenditures		(45,317	)		(39,103	)
Contributions in aid of construction		6,623			1,871
Other		1,177			1,248

Net cash provided by (used in) investing activities		(98,963	)		1,703

Cash flows from financing activities
Net increase in deposit liabilities		52,980			70,706
Net increase in short-term borrowings with maturities of three months or less		40,826			23,496
Net increase in retail repurchase agreements		7,864			5,428
Proceeds from other borrowings		206,490			352,950
Repayments of other borrowings		(214,300	)		(407,031	)
Proceeds from issuance of long-term debt		—			48,485
Repayment of long-term debt		(10,000	)		(47,000	)
Excess tax benefits from share-based payment arrangements		316			—
Net proceeds from issuance of common stock		103			—
Common stock dividends		(25,112	)		(25,006	)
Other		(6,294	)		(4,994	)

Net cash provided by financing activities		52,873			17,034

Cash flows from discontinued operations-net cash provided by (used in) operating activities (revised see Note 8)		6,958			(422	)

Net increase in cash and equivalents and federal funds sold		31,667			65,829
Cash and equivalents and federal funds sold, beginning of period		208,947			173,629

Cash and equivalents and federal funds sold, end of period	$	240,614		$	239,458

See accompanying “Notes to Consolidated Financial Statements” for HEI.

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 accounting principles generally accepted in the United States of America (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 should be read in conjunction with the audited consolidated financial statements and the notes thereto included in HEI’s Form 10-K for the year ended December 31, 2005.

In the opinion of HEI’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to present fairly the Company’s financial position as of March 31, 2006 and December 31, 2005 and the results of its operations and cash flows for the three months ended March 31, 2006 and 2005. All such adjustments are of a normal recurring nature, unless otherwise disclosed in this Form 10–Q or other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year. When required, certain reclassifications are made to the prior period’s consolidated financial statements to conform to the current presentation.

(2) Segment financial information


(in thousands)	Electric Utility		Bank		Other			Total
Three months ended March 31, 2006
Revenues from external customers	$	474,986	$	100,004	$	(28	)	$	574,962
Intersegment revenues (eliminations)		70		—		(70	)		—

Revenues		475,056		100,004		(98	)		574,962

Profit (loss)*		34,097		27,015		(9,301	)		51,811
Income taxes (benefit)		13,109		10,188		(3,823	)		19,474

Net income (loss)		20,988		16,827		(5,478	)		32,337

Assets (at March 31, 2006, including net assets of discontinued operations)		3,076,673		6,864,915		38,120			9,979,708

Three months ended March 31, 2005
Revenues from external customers	$	374,775	$	97,224	$	629		$	472,628

Profit (loss)*		20,083		28,923		(10,132	)		38,874
Income taxes (benefit)		7,698		11,162		(4,081	)		14,779

Net income (loss)		12,385		17,761		(6,051	)		24,095

Assets (at March 31, 2005, including net assets of discontinued operations)		2,876,934		6,762,868		70,383			9,710,185

*	Income (loss) before income taxes.

Intercompany electric sales of consolidated HECO 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.

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.

(3) Electric utility subsidiary

For HECO’s consolidated financial information, including its commitments and contingencies, see pages 14 through 31.

(4) Bank subsidiary

Selected financial information

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

Consolidated Balance Sheet Data (unaudited)


(in thousands)	March 31, 2006			December 31, 2005
Assets
Cash and equivalents	$	151,990		$	150,130
Federal funds sold		85,232			57,434
Available-for-sale investment and mortgage-related securities		2,609,160			2,629,351
Investment in stock of Federal Home Loan Bank of Seattle, at cost		97,764			97,764
Loans receivable, net		3,618,246			3,566,834
Other		213,623			244,443
Goodwill and other intangibles, net		88,900			89,379

	$	6,864,915		$	6,835,335

Liabilities and stockholder’s equity
Deposit liabilities–noninterest-bearing	$	641,844		$	624,497
Deposit liabilities–interest-bearing		3,968,555			3,932,922
Other borrowings		1,623,287			1,622,294
Other		79,721			98,189

		6,313,407			6,277,902

Common stock		321,792			321,538
Retained earnings		279,867			272,545
Accumulated other comprehensive loss, net of tax benefits		(50,151	)		(36,650	)

		551,508			557,433

	$	6,864,915		$	6,835,335

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

Consolidated Statements of Income Data (unaudited)


	Three months ended March 31
(in thousands)	2006		2005
Interest and dividend income
Interest and fees on loans	$	55,153	$	48,513
Interest and dividends on investment and mortgage-related securities		30,077		34,863

		85,230		83,376

Interest expense
Interest on deposit liabilities		15,393		12,017
Interest on other borrowings		17,162		17,748

		32,555		29,765

Net interest income		52,675		53,611
Reversal of allowance for loan losses		—		(3,100	)

Net interest income after reversal of allowance for loan losses		52,675		56,711

Noninterest income
Fees from other financial services		6,440		5,863
Fee income on deposit liabilities		4,189		4,171
Fee income on other financial products		2,437		2,435
Other income		1,708		1,379

		14,774		13,848

Noninterest expense
Compensation and employee benefits		17,837		16,627
Occupancy		4,463		4,018
Equipment		3,496		3,399
Services		3,717		3,667
Data processing		2,460		3,045
Other expense		8,461		10,850

		40,434		41,606

Income before minority interests and income taxes		27,015		28,953
Minority interests		—		27
Income taxes		10,188		11,162

Income before preferred stock dividends		16,827		17,764
Preferred stock dividends		—		3

Net income for common stock	$	16,827	$	17,761

Other borrowings consisted of securities sold under agreements to repurchase and advances from the Federal Home Loan Bank (FHLB) of Seattle of $724 million and $899 million, respectively, as of March 31, 2006 and $687 million and $935 million, respectively, as of December 31, 2005.

As of March 31, 2006, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.1 billion.

In the first quarter of 2005, ASB recorded a $2 million reserve, net of taxes, for interest on the potential taxes related to the disputed timing of dividend income recognition because of a change in ASB’s 2000 and 2001 tax year-ends (see Note 10).

(5) Retirement benefits

For the first quarter of 2006, ASB paid $1 million and HECO paid $3 million of contributions to the retirement benefit plans, compared to $6 million and $3 million, respectively, in the first quarter of 2005. The Company’s current estimate of contributions to the retirement benefit plans in 2006 is $14 million, compared to contributions of $25 million in 2005.

The components of net periodic benefit cost were as follows:


	Three months ended March 31
	Pension benefits						Other benefits
(in thousands)	2006			2005			2006			2005
Service cost	$	8,091		$	7,283		$	1,271		$	1,273
Interest cost		13,476			13,058			2,732			2,808
Expected return on plan assets		(17,753	)		(18,374	)		(2,466	)		(2,485	)
Amortization of unrecognized transition obligation		1			1			784			784
Amortization of prior service cost (gain)		(156	)		(146	)		3			3
Recognized actuarial loss		3,111			1,594			224			159

Net periodic benefit cost	$	6,770		$	3,416		$	2,548		$	2,542

Of the net periodic benefit costs, the Company recorded expense of $7 million and $5 million in the first quarter of 2006 and 2005, respectively, and charged the remaining amounts primarily to electric utility plant.

(6) Share-based compensation

Under the 1987 Stock Option and Incentive Plan, as amended (SOIP), HEI may issue an aggregate of 9.3 million shares of common stock (5,358,572 shares unissued as of March 31, 2006) to officers and key employees as incentive stock options, nonqualified stock options, restricted stock, stock appreciation rights (SARs), stock payments or dividend equivalents. HEI has issued nonqualified stock options, SARs, restricted stock and dividend equivalents.

For the nonqualified stock options and SARs, the exercise price of each option or SAR generally equals the fair market value of HEI’s stock on or near the date of grant. Options and SARs and related dividend equivalents issued in the form of stock awarded through 2004 generally become exercisable in installments of 25% each year for four years, and expire if not exercised ten years from the date of the grant. The 2005 SARs awards, which have a ten year exercise life, generally become exercisable at the end of four years with the related dividend equivalents issued in the form of stock on an annual basis. Accelerated vesting is provided in the event of a change-in-control or upon retirement.

Restricted stock grants generally become unrestricted three to five years after the date of grant and restricted stock compensation expense has been recognized in accordance with the fair value based method of accounting.

The Company recorded share-based compensation expense in the first quarters of 2006 and 2005 of $0.5 million and $1.2 million, respectively. The Company recorded related income tax benefit (including a valuation allowance due to limits on the deductibility of executive compensation) on share-based compensation expense in the first quarters of 2006 and 2005 of $0.2 million and $0.3 million, respectively. No share-based compensation cost has been capitalized.

In the first quarters of 2006 and 2005, no share-based compensation was granted, vested, forfeited or expired. See “Nonqualified stock options” below for first quarter of 2006 exercises. There were no exercises during the first quarter of 2005. Also, as a result of the changes for Section 409A of the Internal Revenue Code of 1986, as amended (Section 409A) in December 2005, a total of 61,482 dividend equivalent shares were paid out to SOIP participants in February 2006 for the stock option grants in 2001 to 2003 and SARs grants in 2004 and 2005. The gross amount of 69,737 dividend equivalent shares subject to 409A was reduced by 8,255 shares because the exercise prices of the SARs grants exceeded the value of the underlying common stock as of December 31, 2005. The intrinsic value of the 409A dividend equivalent payout was $1.6 million. The Company recorded related income tax benefits of $0.6 million. See “Restricted stock” for April 13, 2006 grant. For all share-based compensation, the estimated forfeiture rate is 1.4%.

Nonqualified stock options. Information about HEI’s nonqualified stock options are summarized as follows:


March 31, 2006			Outstanding				Exercisable
Year of grant	Range of exercise prices		Number of options	Weighted- average remaining contractual life	Weighted- average exercise price		Number of options	Weighted- average remaining contractual life	Weighted- average exercise price
1998	$	20.50	6,000	2.1	$	20.50	6,000	2.1	$	20.50
1999		17.61 - 17.63	65,000	3.3		17.62	65,000	3.3		17.62
2000		14.74	52,000	4.1		14.74	52,000	4.1		14.74
2001		17.96	140,500	5.1		17.96	140,500	5.1		17.96
2002		21.68	250,000	6.1		21.68	186,500	6.1		21.68
2003		20.49	409,500	7.1		20.49	195,500	7.1		20.49

	$	14.74–21.68	923,000	6.0	$	19.90	645,500	5.7	$	19.53

As of December 31, 2005, nonqualified stock option shares outstanding totaled 929,000, with a weighted-average exercise price of $19.88. During the first quarter of 2006, 6,000 shares were exercised, with a weighted-average exercise price of $17.31. Cash received from this exercise was $104,000 and the intrinsic value (amount by which the fair market value of the underlying stock exceeds the exercise price of the option plus the fair market value of the related dividend equivalents) of the shares was $109,000. The actual tax benefit realized for the tax deduction from this exercise was $42,000.

As of March 31, 2006, nonqualified stock option shares outstanding and exercisable had an aggregate intrinsic value (including dividend equivalents) of $10.8 million and $8.2 million, respectively.

As of March 31, 2006, there was $0.4 million of total unrecognized compensation cost related to nonvested stock options and that cost is expected to be recognized over a weighted average period of one year.

Stock appreciation rights. Information about HEI’s stock appreciation rights are summarized as follows:


March 31, 2006			Outstanding				Exercisable
Year of grant	Range of exercise prices		Number of underlying shares of SARs	Weighted- average remaining contractual life	Weighted- average exercise price		Number of underlying shares of SARs	Weighted- average remaining contractual life	Weighted- average exercise price
2004	$	26.02	325,000	8.1	$	26.02	81,250	8.1	$	26.02
2005		26.18	554,000	9.1		26.18	—	—		—

	$	26.02 – 26.18	879,000	8.7	$	26.12	81,250	8.1	$	26.02

As of December 31, 2005, stock appreciation rights shares outstanding totaled 879,000, with a weighted-average exercise price of $26.12. As of March 31, 2006, the stock appreciation rights shares outstanding and exercisable had an aggregate intrinsic value (including dividend equivalents) of $1.7 million and $0.2 million, respectively.

As of March 31, 2006, there was $2.2 million of total unrecognized compensation cost related to SARs and that cost is expected to be recognized over a weighted average period of 2.8 years.

The weighted-average fair value of each of the SARs granted during 2005 was $5.82 (at grant date). For 2005, the weighted-average assumptions used to estimate fair value include: risk-free interest rate of 4.1%, expected volatility of 18.1%, expected dividend yield of 5.9%, term of 10 years and expected life of 4.5 years. The weighted-average fair value of the SARs grant is estimated on the date of grant using a Binomial Option Pricing Model. See below for discussion of 2005 grant modification. The expected volatility is based on historical price fluctuations. The Company believes that historical volatility is appropriate based upon the Company’s business model and strategies.

Section 409A modification. As noted above, in December 2005, to comply with Section 409A, HEI modified certain provisions pertaining to the dividend equivalent rights attributable to the outstanding grants of nonqualified stock options and SARs held by 40 employees under the 1987 HEI Stock Option and Incentive Plan, as amended. The modifications apply to the nonqualified stock options granted in 2001, 2002, and 2003 and the SARs granted in 2004 and 2005. When a share-based award is modified, the Company recognizes the incremental compensation cost, which is measured as the excess, if any, of the fair value of the modified award over the fair value of the original award immediately before its terms are modified.

The assumptions used to estimate fair value at the time of the Section 409A modification for the 2005 SARs include: risk-free interest rate of 4.4%, expected volatility of 14.9%, expected dividend yield of 4.6%. The expected life used at the time of modification was 4.2 years for 2005. As of December 7, 2005, the fair value of modified 2005 SAR, the fair value of original 2005 SAR and the additional compensation cost to be recognized per grant was $5.07, $4.95 and $0.12, respectively. The additional compensation cost for the Section 409A modification was not material.

Restricted stock. As of December 31, 2005 and March 31, 2006, restricted stock shares outstanding totaled 41,000, with a weighted-average grant date fair value of $23.50.

The actual tax benefit realized for the tax deductions from restricted stock dividends totaled were immaterial for the first quarters of 2006 and 2005.

As of March 31, 2006, there was $0.4 million of total unrecognized compensation cost related to nonvested restricted stock. The cost is expected to be recognized over a period of 2.9 years.

In place of a SARs grant for 2006, on April 13, 2006, 60,800 shares of restricted stock were granted to officers and key employees with a fair market value of $1.6 million.

(7) Commitments and contingencies

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

(8) Cash flows

Supplemental disclosures of cash flow information

For the three months ended March 31, 2006 and 2005, the Company paid interest amounting to $39.1 million and $36.6 million, respectively.

For the three months ended March 31, 2006 and 2005, the Company paid income taxes amounting to $1.9 million and $11.8 million (including payment for bank franchise taxes for the three months ended March 31, 2005 related to a prior year settlement), respectively.

Supplemental disclosures of noncash activities

Noncash increases in common stock for director and officer compensatory plans were $0.8 million and $1.9 million for the three months ended March 31, 2006 and 2005, respectively.

Revised cash flows from discontinued operations

The Company has separately disclosed the operating, investing and financing portions of the cash flows attributable to its discontinued operations for the first quarter of 2006, which in the first quarter of 2005 were reported on a combined basis as a single amount. For the first quarter of 2006 and 2005, there were no cash flows from investing and financing activities from the Company’s discontinued operations.

(9) Recent accounting pronouncements and interpretations

For a discussion of a recent accounting pronouncement regarding variable interest entities (VIEs), see Note 7 of HECO’s “Notes to Consolidated Financial Statements.”

Other-than-temporary impairment and its application to certain investments

In March 2004, the FASB ratified EITF Issue No. 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments.” EITF Issue No. 03-1 provides guidance for determining whether an investment in debt or equity securities is impaired, evaluating whether an impairment is other-than-temporary and measuring impairment. EITF Issue No. 03-1 also provides disclosure guidance. The recognition and measurement guidance would have applied prospectively to all current and future investments within the scope of EITF Issue No. 03-1 in reporting periods beginning after June 15, 2004. However, in September 2004, the FASB issued FASB Staff Position (FSP) EITF 03-1-1 to delay the effective date of the recognition and measurement guidance. At its June 29, 2005 meeting, the FASB decided not to provide additional guidance on the meaning of other-than-temporary impairment, but directed its staff to issue proposed FSP EITF 03-1-a as final (retitled as FSP FAS 115-1 and FAS 124-1). The guidance in FSP FAS 115-1 and FAS 124-1 addresses the determination of when an investment is considered impaired, whether that impairment is other than temporary, and the measurement of an impairment loss. The FSP also includes accounting considerations subsequent to the recognition of an other-than-temporary impairment and requires certain disclosures about unrealized losses that have not been recognized as other-than-temporary impairments. The guidance in this FSP amends FASB Statement No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” and FASB Statement No. 124, “Accounting for Certain Investments Held by Not-for-Profit Organizations,” and adds a footnote to APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” The guidance in this FSP nullifies certain requirements of EITF

Issue No. 03-1 and supersedes EITF Abstracts, Topic D-44, “Recognition of Other-Than-Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value.” The guidance in this FSP is required to be applied to reporting periods beginning after December 15, 2005. The Company adopted FSP FAS 115-1 on January 1, 2006 and the adoption had no effect on the Company’s financial statements.

Share-based payment

In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment,” which requires companies to recognize the grant-date fair value of stock options and other equity-based compensation issued to employees in the income statement. In March 2005, the SEC issued Staff Accounting Bulletin (SAB) No. 107, which provides accounting, disclosure, valuation and other guidance related to share-based payment arrangements. The Company adopted the provisions of SFAS No. 123 (revised 2004) using a modified prospective application and the guidance in SAB No. 107 on January 1, 2006 and the net income impact of adoption was immaterial. Since the Company adopted the recognition provisions of SFAS No. 123 as of January 1, 2002, the only expense recognition change the Company made upon adoption of SFAS No. 123 (revised 2004) was how it accounts for forfeitures. The average annual forfeiture rate for 1996 through 2005 was 1.4% and historically has not been significant. In accordance with SFAS No. 123 (revised 2004), expanded disclosures are included in Note 6.

Accounting changes and error corrections

In June 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections.” This standard replaces APB Opinion No. 20, “Accounting Changes,” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements.” Among other changes, SFAS No. 154 requires that a voluntary change in accounting principle be applied retrospectively so that all prior period financial statements presented are based on the new accounting principle, unless it is impracticable to do so. SFAS No. 154 also provides that (1) a change in method of depreciating or amortizing a long-lived nonfinancial asset be accounted for as a change in estimate (prospectively) that was effected by a change in accounting principle, and (2) correction of errors in previously issued financial statements should be termed a “restatement.” SFAS No. 154 is effective for accounting changes and error corrections made in fiscal years beginning after December 15, 2005. The Company adopted SFAS No. 154 on January 1, 2006 and the adoption had no effect on the Company’s financial statements.

Accounting for certain hybrid financial instruments

In March 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments.” This statement amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” This statement permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, and clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives. SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of the first fiscal year that begins after September 15, 2006. The Company will adopt SFAS No. 155 on January 1, 2007. Because the impact of adopting the provisions of SFAS No. 155 will be dependent on future events and circumstances, management cannot predict such impact.

Accounting for servicing of financial assets

In March 2006, the FASB issued SFAS No. 156, “Accounting for Servicing of Financial Assets.” This statement amends SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” This statement requires an entity to recognize in certain situations a servicing asset or servicing liability when it undertakes an obligation to service a financial asset, requires all separately recognized servicing assets and liabilities to be initially measured at fair value (if practicable), permits alternative subsequent measurement methods for each class of servicing assets and liabilities, permits a limited one-time reclassification of available-for-sale securities to trading securities at adoption, requires separate presentation of servicing assets and liabilities subsequently measured at fair value in the balance sheet and requires additional disclosures. SFAS No. 156 must be adopted by the beginning of the first fiscal year that begins after September 15, 2006. The Company will adopt SFAS

No. 156 on January 1, 2007 and management does not expect the impact of adoption will be material to the Company’s financial statements.

(10) Income taxes

In the first quarter of 2005, the Company recorded a $2 million reserve, net of taxes, for interest on the potential taxes related to the disputed timing of dividend income recognition because of a change in ASB’s 2000 and 2001 tax year-ends. In the second quarter of 2005, the Company made a $30 million deposit primarily to stop the further accrual of interest on the potential taxes related to the disputed timing of dividend income recognition. Also in the second quarter of 2005, $1 million of income taxes and interest payable, net of taxes, were reversed due to the resolution of audit issues with the Internal Revenue Service (IRS). In the fourth quarter of 2005, additional IRS audit issues were resolved, resulting in the reversal of $1 million of interest, net of taxes.

As of March 31, 2006, $1 million, net of tax effects, was reserved for unresolved tax issues and related interest. Although not probable, adverse developments on unresolved issues could result in additional charges to net income in the future. Based on information currently available, the Company believes it has adequately provided for unresolved income tax issues with federal and state tax authorities and related interest, and that the ultimate resolution of tax issues for all open tax periods will not have a material adverse effect on its results of operations, financial condition or liquidity.

(11) Investment in Hoku Scientific, Inc.

As of March 31, 2006, HEI Properties, Inc. (HEIPI) held shares of Hoku Scientific, Inc. (Hoku), a Hawaii fuel cell technology startup company. Prior to August 5, 2005, the investment had been accounted for under the cost method. Hoku went public and shares of Hoku began trading on the Nasdaq Stock Market on August 5, 2005. HEIPI was subject to certain “lockup” provisions that expired in February 2006. Since August 5, 2005, Hoku shares have been considered marketable and HEIPI has classified the shares as trading securities, carried at fair value with changes in fair value recorded in earnings. In the first quarter of 2006, HEIPI recognized a $0.4 million loss (unrealized and realized), net of taxes, on the Hoku shares. As of March 31, 2006, HEIPI had sold 11% of its Hoku shares and carried its remaining investment in Hoku shares at $4 million.

(12) Credit agreements

Effective April 3, 2006, HEI entered into a revolving unsecured credit agreement establishing a line of credit facility of $100 million, with a letter of credit sub-facility, expiring on March 31, 2011, with a syndicate of eight financial institutions. Any draws on the facility bear interest at the “Adjusted LIBO Rate” plus 50 basis points or the greater of (a) the “Prime Rate” and (b) the sum of the “Federal Funds Rate” plus 50 basis points, as defined in the agreement. Annual fees on undrawn commitments are 10 basis points. The agreement contains customary conditions which must be met in order to draw on it, including compliance with its covenants. In addition to customary defaults, HEI’s failure to maintain its nonconsolidated “Capitalization Ratio” (funded debt) of 50% or less and “Consolidated Net Worth” of $850 million, as defined in its agreement, or meet other requirements will result in an event of default.

These two facilities, currently totaling $175 million, are maintained to support the issuance of commercial paper, but also may be drawn for general corporate purposes. The facilities contain provisions for revised pricing in the event of a ratings change and replaced HEI’s four bilateral bank lines of credit totaling $80 million, which were terminated concurrently with the effectiveness of the new facilities. The Company used the new facilities to support the issuance of commercial paper to refinance its $100 million of Series C medium-term notes, which matured on April 10, 2006. As of May 1, 2006, the $175 million of credit facilities were undrawn.

See Note 10 of HECO’s “Notes to Consolidated Financial Statements” for a discussion of HECO’s credit facility.

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)


(in thousands, except par value)	March 31, 2006			December 31, 2005
Assets
Utility plant, at cost
Land	$	33,188		$	33,034
Plant and equipment		3,816,070			3,749,386
Less accumulated depreciation		(1,482,595	)		(1,456,537	)
Plant acquisition adjustment, net		132			145
Construction in progress		123,530			147,756

Net utility plant		2,490,325			2,473,784

Current assets
Cash and equivalents		1,884			143
Customer accounts receivable, net		112,170			123,895
Accrued unbilled revenues, net		81,408			91,321
Other accounts receivable, net		10,156			14,761
Fuel oil stock, at average cost		93,283			85,450
Materials and supplies, at average cost		28,795			26,974
Prepaid pension benefit cost		101,378			106,318
Other		7,398			8,584

Total current assets		436,472			457,446

Other long-term assets
Regulatory assets		111,438			110,718
Unamortized debt expense		14,179			14,361
Other		24,259			25,152

Total other long-term assets		149,876			150,231

	$	3,076,673		$	3,081,461

Capitalization and liabilities
Capitalization
Common stock, $6 2/3 par value, authorized 50,000 shares; outstanding 12,806 shares	$	85,387		$	85,387
Premium on capital stock		299,186			299,186
Retained earnings		662,034			654,686

Common stock equity		1,046,607			1,039,259
Cumulative preferred stock – not subject to mandatory redemption		34,293			34,293
Long-term debt, net		766,041			765,993

Total capitalization		1,846,941			1,839,545

Current liabilities
Short-term borrowings–nonaffiliates		145,157			136,165
Accounts payable		115,465			122,201
Interest and preferred dividends payable		14,441			9,990
Taxes accrued		114,111			133,583
Other		31,761			37,132

Total current liabilities		420,935			439,071

Deferred credits and other liabilities
Deferred income taxes		203,972			208,374
Regulatory liabilities		224,598			219,204
Unamortized tax credits		56,242			55,327
Other		63,293			63,677

Total deferred credits and other liabilities		548,105			546,582

Contributions in aid of construction		260,692			256,263

	$	3,076,673		$	3,081,461

See accompanying “Notes to Consolidated Financial Statements” for HECO.

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)


	Three months ended March 31
(in thousands, except ratio of earnings to fixed charges)	2006			2005
Operating revenues	$	473,971		$	373,690

Operating expenses
Fuel oil		175,338			115,626
Purchased power		117,720			101,216
Other operation		42,019			41,316
Maintenance		17,052			17,938
Depreciation		32,533			30,820
Taxes, other than income taxes		44,523			35,971
Income taxes		13,224			7,738

		442,409			350,625

Operating income		31,562			23,065

Other income
Allowance for equity funds used during construction		1,548			1,087
Other, net		909			843

		2,457			1,930

Income before interest and other charges		34,019			24,995

Interest and other charges
Interest on long-term debt		10,778			10,909
Amortization of net bond premium and expense		543			556
Other interest charges		1,913			1,073
Allowance for borrowed funds used during construction		(702	)		(427	)
Preferred stock dividends of subsidiaries		229			229

		12,761			12,340

Income before preferred stock dividends of HECO		21,258			12,655
Preferred stock dividends of HECO		270			270

Net income for common stock	$	20,988		$	12,385

Ratio of earnings to fixed charges (SEC method)		3.38			2.51

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Retained Earnings (unaudited)


	Three months ended March 31
(in thousands)	2006			2005
Retained earnings, beginning of period	$	654,686		$	632,779
Net income for common stock		20,988			12,385
Common stock dividends		(13,640	)		(9,933	)

Retained earnings, end of period	$	662,034		$	635,231

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

See accompanying “Notes to Consolidated Financial Statements” for HECO.

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)


(in thousands)	Three months ended March 31
(in thousands)	2006			2005
Cash flows from operating activities
Income before preferred stock dividends of HECO	$	21,258		$	12,655
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities
Depreciation of property, plant and equipment		32,533			30,820
Other amortization		1,678			2,223
Deferred income taxes		(4,390	)		(1,398	)
Tax credits, net		1,229			693
Allowance for equity funds used during construction		(1,548	)		(1,087	)
Changes in assets and liabilities
Decrease in accounts receivable		16,330			15,509
Decrease in accrued unbilled revenues		9,913			13,527
Increase in fuel oil stock		(7,833	)		(6,874	)
Increase in materials and supplies		(1,821	)		(1,451	)
Decrease in prepaid pension benefit cost		4,940			1,901
Increase in regulatory assets		(1,119	)		(279	)
Decrease in accounts payable		(6,736	)		(9,507	)
Decrease in taxes accrued		(19,472	)		(23,519	)
Changes in other assets and liabilities		3,992			469

Net cash provided by operating activities		48,954			33,682

Cash flows from investing activities
Capital expenditures		(43,079	)		(37,757	)
Contributions in aid of construction		6,623			1,871
Other		108			1,423

Net cash used in investing activities		(36,348	)		(34,463	)

Cash flows from financing activities
Common stock dividends		(13,640	)		(9,933	)
Preferred stock dividends		(270	)		(270	)
Proceeds from issuance of long-term debt		—			48,485
Repayment of long-term debt		—			(47,000	)
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		8,992			22,002
Other		(5,947	)		(4,853	)

Net cash provided by (used in) financing activities		(10,865	)		8,431

Net increase in cash and equivalents		1,741			7,650
Cash and equivalents, beginning of period		143			327

Cash and equivalents, end of period	$	1,884		$	7,977

See accompanying “Notes to Consolidated Financial Statements” for HECO.

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 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, 2005.

In the opinion of HECO’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to present fairly the financial position of HECO and its subsidiaries as of March 31, 2006 and December 31, 2005 and the results of their operations and cash flows for the three months ended March 31, 2006 and 2005. All such adjustments are of a normal recurring nature, unless otherwise disclosed in this Form 10-Q or other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year. When required, certain reclassifications are made to the prior period’s consolidated financial statements to conform to the current presentation.

(2) Unconsolidated variable interest entities

HECO Capital Trust III

HECO Capital Trust III (Trust III) was created and exists for the exclusive purposes of (i) issuing in March 2004 2,000,000 6.50% Cumulative Quarterly Income Preferred Securities, Series 2004 (2004 Trust Preferred Securities) ($50 million aggregate liquidation preference) to the public and trust common securities ($1.5 million aggregate liquidation preference) to HECO, (ii) investing the proceeds of these trust securities in 2004 Debentures issued by HECO in the principal amount of $31.5 million and issued by each of Maui Electric Company, Limited (MECO) and Hawaii Electric Light Company, Inc. (HELCO) in the respective principal amounts of $10 million, (iii) making distributions on the 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 redeemable at the issuer’s option without premium beginning on March 18, 2009. The 2004 Debentures, together with the obligations of HECO, MECO and HELCO under an expense agreement and HECO’s obligations under its trust guarantee and its guarantee of the obligations of MECO and HELCO 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 FIN 46R, “Consolidation of Variable Interest Entities.” Trust III’s balance sheets as of March 31, 2006 and December 31, 2005 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 three months ended March 31, 2006 and 2005 each consisted of $0.8 million of interest income received from the 2004 Debentures; $0.8 million of distributions to holders of the Trust Preferred Securities; and $25,000 of common dividends on the trust common securities to HECO. So long as the 2004 Trust Preferred Securities are outstanding, HECO is not entitled to receive any funds from Trust III other than pro rata distributions, subject to certain subordination provisions, on the trust common securities. In the event of a default by HECO in the performance of its obligations under the 2004 Debentures or under its Guarantees, or in the event HECO, HELCO or MECO elect to defer payment of interest on any of their respective 2004 Debentures, then HECO will be subject to a number of restrictions, including a prohibition on the payment of dividends on its common stock.

Purchase power agreements

As of March 31, 2006, the Company had six purchase power agreements (PPAs) for a total of 540 megawatts (MW) of firm capacity, and other PPAs with smaller independent power producers (IPPs) and Schedule Q providers that supplied as-available energy. Approximately 91% of the 540 MW of firm capacity is under PPAs, entered into before December 31, 2003, with AES Hawaii, Inc. (AES Hawaii), Kalaeloa Partners, L.P. (Kalaeloa), Hamakua Energy Partners, L.P. (HEP) and HPower. Purchases from all IPPs for the three months ended March 31, 2006 totaled $118 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPower totaling $29 million, $46 million, $15 million and $11 million, respectively. The primary business activities of these IPPs are the generation and sale of power to the Company (and municipal waste disposal in the case of HPower). Current financial information about the size, including total assets and revenues, for many of these IPPs is not publicly available. Under FIN 46R, 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 FIN 46R to that entity if the enterprise is unable to obtain, after making an exhaustive effort, the necessary information.

The Company has reviewed its significant PPAs and determined that the IPPs had no contractual obligation to provide such information. In March 2004, the Company sent letters to all of their IPPs, except the Schedule Q providers, requesting the information that they need to determine the applicability of FIN 46R to the respective IPP, and subsequently contacted most of the IPPs to explain and repeat its request for information. (The Company excluded their Schedule Q providers from the scope of FIN 46R because its variable interest in the provider would not be significant to the Company and they did not participate significantly in the design of the provider.) Some of the IPPs provided sufficient information for the Company to determine that the IPP was not a VIE, or was either a “business” or “governmental organization” (HPower) as defined under FIN 46R, and thus excluded from the scope of FIN 46R. Other IPPs, including the three largest, declined to provide the information necessary for the Company to determine the applicability of FIN 46R, and the Company was unable to apply FIN 46R to these IPPs. In January 2005 and 2006 the Company again sent letters to the IPPs that were not excluded from the scope of FIN 46R, requesting the information required to determine the applicability of FIN 46R to the respective IPP. All of these IPPs again declined to provide the necessary information. Kalaeloa has since provided its information (see below).

As required under FIN 46R, the Company has continued its efforts to obtain from the IPPs the information necessary to make the determinations required under FIN 46R. If the requested information is ultimately received, a possible outcome of future analysis is the consolidation of an IPP in HECO’s consolidated financial statements. The consolidation of any significant IPP could have a material effect on HECO’s consolidated financial statements, including the recognition of a significant amount of assets and liabilities, and, if such a consolidated IPP were operating at a loss and had insufficient equity, the potential recognition of such losses.

Kalaeloa Partners, L.P. In October 1988, HECO entered into a power purchase agreement (PPA) with Kalaeloa, which provided that HECO would purchase 180 MW of firm capacity for a period of 25 years beginning in May 1991. In October 2004, HECO and Kalaeloa entered into amendments, which together effectively increased the firm capacity from 180 MW to 208 MW. The PPA and amendments have been approved by the PUC. The energy payments that HECO makes to Kalaeloa include: 1) a fuel component, with a fuel price adjustment based on the cost of low sulfur fuel oil, 2) a fuel additives cost component, and 3) a non-fuel component, with an adjustment based on changes in the Gross National Product Implicit Price Deflator. The capacity payments that HECO makes to Kalaeloa are fixed in accordance with the PPA.

Kalaeloa is a Delaware limited partnership formed on October 13, 1988 for the purpose of designing, constructing, owning and operating a 200 MW cogeneration facility on Oahu, which includes two 75 MW oil-fired combustion turbines, two waste heat recovery steam generators, a 50 MW turbine generator and other electrical, mechanical and control equipment. The two combustion turbines were upgraded during 2004 resulting in an increase in the facility’s nominal output rating to approximately 220 MW. Kalaeloa has a PPA with HECO (described above) and a steam delivery contract with another customer, the term of which coincides with the PPA. The facility has been certified by the Federal Energy Regulatory Commission as a Qualified Facility under the Public Utilities Regulatory Policies Act of 1978.

Pursuant to the provisions of FIN 46R, HECO is deemed to have a variable interest in Kalaeloa via HECO’s PPA with Kalaeloa. However, management has concluded that HECO is not the primary beneficiary of Kalaeloa because HECO does not absorb the majority of Kalealoa’s expected losses nor receive a majority of Kalaeloa’s expected residual returns and, thus, HECO has not consolidated Kalaeloa in its consolidated financial statements. A significant factor which affected the level of expected losses HECO would absorb is the fact that HECO’s exposure to fuel price variability is limited to the remaining term of the PPA as compared to the facility’s remaining useful life. Although HECO absorbs fuel price variability for the remaining term of the PPA, the PPA does not expose HECO to losses as the fuel and fuel related energy payments under the PPA have been approved by the PUC for recovery from customers through base electric rates and through HECO’s energy cost adjustment clause to the extent the fuel and fuel related energy payments are not included in base energy rates.

Apollo Energy Corporation and Kaheawa Wind Power, LLC In October 2004, HELCO and Apollo Energy Corporation (Apollo) executed a restated and amended PPA which enables Apollo to repower its 7 MW facility, and install additional capacity, for a total allowed capacity of 20 MW. The PUC approved the restated and amended PPA on March 10, 2005. Due to initial problems with securing wind turbines from its supplier, Apollo had earlier informed HELCO that the project may be delayed. However, Apollo recently informed HELCO that its wind turbine supply problems have been resolved and it can now meet the April 2007 target for commercial operation. In December 2004, MECO executed a new PPA with Kaheawa Wind Power, LLC (KWP), which is installing a 30 MW windfarm on Maui. The revised PPA with Apollo and new PPA with KWP were approved by the PUC in March 2005, and became effective in April 2005. The PPAs require Apollo and KWP to provide information necessary to (1) determine if HELCO and MECO must consolidate Apollo and KWP, respectively, under FIN 46R, (2) consolidate Apollo and/or KWP, if necessary under FIN 46R, and (3) comply with Section 404 of Sarbanes-Oxley Act of 2002 (SOX). Management is in the process of obtaining the information necessary to complete its determination of whether Apollo or KWP are VIEs and, if so, whether HELCO or MECO, respectively, is the primary beneficiary. Based on information currently available, management believes the impact on consolidated HECO’s financial statements of the consolidation of Apollo and/or KWP, if necessary, would not be material. However, depending on the magnitude of the improvements contemplated in the PPAs, the impact of a required consolidation of Apollo and KWP could be material in the future. If required to consolidate the financial statements of Apollo and/or KWP in the future and such consolidation had a material effect, HECO would retrospectively apply FIN 46R in accordance with SFAS No. 154, “Accounting Changes and Error Corrections.”

(3) Revenue taxes

HECO and its subsidiaries’ operating revenues include amounts for various revenue taxes. Revenue taxes are generally recorded as an expense in the period the related revenues are recognized. HECO and its subsidiaries’ payments to the taxing authorities are based on the prior year’s revenues. For the three months ended March 31, 2006 and 2005, HECO and its subsidiaries included approximately $42 million and $34 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

(4) Retirement benefits

In each of the first quarters of 2006 and 2005, HECO and its subsidiaries paid contributions of $3 million to the retirement benefit plans. HECO and its subsidiaries’ current estimate of contributions to the retirement benefit plans in 2006 is $11 million, compared to their contributions of $18 million in 2005.

The components of net periodic benefit cost were as follows:


	Three months ended March 31
	Pension benefits						Other benefits
(in thousands)	2006			2005			2006			2005
Service cost	$	6,540		$	5,874		$	1,235		$	1,237
Interest cost		12,039			11,716			2,659			2,736
Expected return on plan assets		(15,932	)		(16,650	)		(2,427	)		(2,448	)
Amortization of unrecognized transition obligation		1			1			782			782
Amortization of prior service gain		(193	)		(188	)		—			—
Recognized actuarial loss		2,714			1,257			213			147

Net periodic benefit cost	$	5,169		$	2,010		$	2,462		$	2,454

Of the net periodic benefit costs, HECO and its subsidiaries recorded expense of $6 million and $3 million in the first quarter of 2006 and 2005, respectively, and charged the remaining amounts primarily to electric utility plant.

(5) Commitments and contingencies

Interim increases

On September 27, 2005, the PUC issued an Interim Decision and Order (D&O) granting a general rate increase on Oahu of 4.36%, or $53.3 million (3.33%, or $41.1 million excluding the transfer of certain costs from a surcharge line item on electric bills into base electricity charges). The tariff changes implementing the interim rate increase were effective September 28, 2005.

As of March 31, 2006, HECO and its subsidiaries had recognized $44 million of revenues with respect to interim orders ($18 million related to interim orders regarding certain integrated resource planning costs and $26 million related to an interim order with respect to Oahu’s general rate increase request), which revenues are subject to refund, with interest, if and to the extent they exceed the amounts allowed in final orders.

HELCO power situation

Historical context. In 1991, HELCO began planning to meet increased electric generation demand forecast for 1994. It planned to install at its Keahole power plant two 20 MW combustion turbines (CT-4 and CT-5), followed by an 18 MW heat recovery steam generator (ST-7), at which time these units would be converted to a 56 MW (net) dual train combined-cycle unit. In January 1994, the PUC approved expenditures for CT-4. In 1995, the PUC allowed HELCO to pursue construction of and commit expenditures for CT-5 and ST-7, but noted that such costs are not to be included in rate base until the project is installed and “is used and useful for utility purposes.”

Status. Installation of CT-4 and CT-5 was significantly delayed as a result of land use and environmental permitting delays and related administrative proceedings and lawsuits. However, in 2003, the parties opposing the plant expansion project (other than Waimana Enterprises, Inc. (Waimana), which did not participate in the settlement discussions and opposes the settlement) entered into a settlement agreement with HELCO and several Hawaii regulatory agencies, intended in part to permit HELCO to complete CT-4 and CT-5 (Settlement Agreement). Subsequently, CT-4 and CT-5 were installed and put into limited commercial operation in May and June 2004, respectively. The Board of Land and Natural Resources’ (BLNR’s) construction deadline of July 31, 2005 has been met. Noise mitigation equipment has been installed on CT-4 and CT-5 and the need for additional noise mitigation work for CT-5 (not requiring any further construction) is being examined to ensure compliance with the night-time noise standard applicable to the plant. Currently, HELCO can operate the generating units at Keahole as required to meet its system needs.

Four appeals to the Hawaii Supreme Court by Waimana have been briefed and are awaiting decision. These are appeals to judgments of the Third Circuit Court involving (i) vacating of a November 2002 Final Judgment which had

halted construction; (ii) the BLNR 2003 construction period extension; (iii) the BLNR’s approval of a revocable permit allowing HELCO to use brackish well water as the primary source of water for operating the Keahole plant; and (iv) appeals (now consolidated) by Waimana and another party of judgments upholding the BLNR’s approval of the long-term lease allowing HELCO to use brackish well water. In the third appeal, additional briefs were filed on July 15, 2005 on the question of whether the appeal is moot given the granting by the BLNR of a long-term water lease allowing HELCO to use brackish water. Full implementation of the Settlement Agreement is conditioned on obtaining final dispositions of all litigation pending at the time of the Settlement Agreement. If the remaining dispositions are obtained, as HELCO believes they will be, then HELCO must undertake a number of actions under the Settlement Agreement, including expediting efforts to obtain the permits and approvals necessary for installation of ST-7 with selective catalytic reduction emissions control equipment, assisting the Department of Hawaiian Home Lands in installing solar water heating in its housing projects, supporting the Keahole Defense Coalition’s participation in certain PUC cases, and cooperating with neighbors and community groups (including a Hot Line service). Some of these actions have already commenced.

HELCO’s plans for ST-7 are progressing. In November 2003, HELCO filed a boundary amendment petition (to reclassify the Keahole plant site from conservation land use to urban land use) with the State Land Use Commission, which was approved in October 2005. HELCO obtained County rezoning to a “General Industrial” classification in May 2006, and will commence construction as other necessary permits are obtained.

Costs incurred; management’s evaluation. As of March 31, 2006, HELCO’s capitalized costs incurred in its efforts to put CT-4 and CT-5 into service and to support existing units (excluding costs for pre-air permit facilities) amounted to approximately $110 million, including $43 million for equipment and material purchases, $47 million for planning, engineering, permitting, site development and other costs and $20 million for allowance for funds used during construction (AFUDC) up to November 30, 1998, after which date management decided not to continue accruing AFUDC. The $110 million of costs was reclassified from construction in progress to plant and equipment in 2004 and 2005 and depreciated beginning January 1 of the year following the reclassification.

Management believes that the prospects are good that the remaining Settlement Agreement conditions will be satisfied and that any further necessary permits will be obtained and that the appeals will be favorably resolved. However, HELCO’s electric rates will not change specifically as a result of including CT-4 and CT-5 in plant and equipment until HELCO files a rate increase application and the PUC grants HELCO rate relief. In May 2006, HELCO filed a request for an electric rate increase in part to recover CT-4 and CT-5 costs. Management believes that no adjustment to costs incurred to put CT-4 and CT-5 into service is required as of March 31, 2006. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HELCO may be required to write off a material portion of these costs.

East Oahu Transmission Project (EOTP)

HECO transmits bulk power to the Honolulu/East Oahu area over two major transmission corridors (Northern and Southern). HECO had planned to construct a partial underground/partial overhead 138 kilovolt (kV) line from the Kamoku substation to the Pukele substation, which serves approximately 16% of Oahu’s electrical load, including Waikiki, in order to close the gap between the Southern and Northern corridors and provide a third transmission line to the Pukele substation, but an application for a permit which would have allowed construction in the originally planned route through conservation district lands was denied in June 2002.

HECO continues to believe that the proposed reliability project (the East Oahu Transmission Project) is needed. In December 2003, HECO filed an application with the PUC requesting approval to commit funds (currently estimated at $57 million; see costs incurred below) for a revised EOTP using a 46 kV system. In March 2004, the PUC granted intervenor status to an environmental organization and three elected officials (collectively treated as one party), and a more limited participant status to four community organizations. The environmental review process has been completed and the PUC issued a Finding of No Significant Impact in April 2005. Subject to PUC approval and other construction permits, HECO plans to construct the revised project, none of which is in conservation district lands, in two phases, currently projected for completion in 2007 and 2009.

As of March 31, 2006, the accumulated costs recorded for the EOTP amounted to $27 million, including $12 million of planning and permitting costs incurred prior to 2003, when HECO was denied the approval necessary

for the partial underground/partial overhead 138 kV line, $4 million of planning and permitting costs incurred after 2002, and $11 million for AFUDC. In the written testimony filed in June 2005, the Consumer Advocate’s consultant contended that HECO should always have planned for a project using only the 46 kV system and recommended that HECO be required to expense the $12 million incurred before 2003, and the related AFUDC of $5 million. In rebuttal testimony filed in August 2005, HECO contested the consultant’s recommendation, emphasizing that the originally proposed 138 kV line would have been a more comprehensive and robust solution to the transmission concerns the project addressed. The PUC held an evidentiary hearing on HECO’s application in November 2005. Just prior to the evidentiary hearing, the PUC approved that part of a stipulation between HECO and the Consumer Advocate that this proceeding should determine whether HECO should be given approval to expend funds for the EOTP provided that no part of the EOTP costs may be recovered from ratepayers unless and until the PUC grants HECO recovery in a rate case (which is consistent with other projects), and that the issue as to whether the pre-2003 planning and permitting costs, and related AFUDC, should be included in the project costs is reserved to, and may be raised in, the next HECO rate case (or other proceeding). Management believes no adjustment to project costs is required as of March 31, 2006. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HECO may be required to write off a material portion or all of the project costs incurred in its efforts to put the project into service whether or not it is completed.

Environmental regulation

HEI and its subsidiaries are subject to environmental laws and regulations that regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic substances.

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

Additionally, current environmental laws may require HEI and its subsidiaries to investigate whether releases from historical operations may have contributed to environmental impacts, and, where appropriate, respond to such releases, even if they were not inconsistent with law or standard industrial practices prevailing at the time when they occurred. Such releases may involve area-wide impacts contributed to by multiple potentially responsible parties.

Honolulu Harbor investigation. In 1995, the Department of Health of the State of Hawaii (DOH) issued letters indicating that it had identified a number of parties, including HECO, who appeared to be potentially responsible for historical subsurface petroleum contamination and/or operated their facilities upon petroleum-contaminated land at or near Honolulu Harbor in the Iwilei district of Honolulu. Certain of the identified parties formed a work group to determine the nature and extent of any contamination and appropriate response actions, as well as identify additional potentially responsible parties (PRPs). The U.S. Environmental Protection Agency (EPA) became involved in the investigation in June 2000. Later in 2000, the DOH issued notices to additional PRPs. The parties in the work group and some of the new PRPs (collectively, the Participating Parties) entered into a joint defense agreement and signed a voluntary response agreement with the DOH. The Participating Parties agreed to fund investigative and remediation work using an interim cost allocation method (subject to a final allocation) and have organized a limited liability company to perform the work.

Since 2001, subsurface investigation and assessment have been conducted and several preliminary oil removal tasks have been performed at the Iwilei Unit in accordance with notices of interest issued by the EPA and DOH. Currently, the Participating Parties are preparing Remedial Alternatives Analyses, which will identify and recommend remedial approaches. HECO routinely maintains its facilities and has investigated its operations in the Iwilei area and ascertained that they are not releasing petroleum.

In 2001, management developed a preliminary estimate of HECO’s share of costs for continuing investigative work, remedial activities and monitoring at the Iwilei Unit of approximately $1.1 million (which was expensed in 2001 and of which $0.6 million has been incurred through March 31, 2006). Because (1) the full scope and extent of additional investigative work, remedial activities and monitoring are unknown at this time, (2) the final cost allocation

method among the PRPs has not yet been determined and (3) management cannot estimate the costs to be incurred (if any) for the sites other than the Iwilei Unit (including its Honolulu power plant site), the cost estimate may be subject to significant change and additional material investigative and remedial costs may be incurred.

Regional Haze Rule amendments. In June 2005, the EPA finalized amendments to the July 1999 Regional Haze Rule that require emission controls known as best available retrofit technology (BART) for industrial facilities emitting air pollutants that reduce visibility in National Parks by causing or contributing to regional haze. States must develop BART implementation plans and schedules in accordance with the amended regional haze rule by December 2007. After Hawaii adopts its plan, HECO, HELCO and MECO will evaluate the impacts, if any, on them. If any of the utilities’ units are ultimately required to install post-combustion control technologies to meet BART emission limits, the capital and operations and maintenance costs could be significant.

Clean Water Act. Section 316(b) of the federal Clean Water Act requires that the EPA ensure that existing power plant cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts. Effective September 9, 2004, the EPA issued a new rule, which establishes location and technology-based design, construction and capacity standards for existing cooling water intake structures. These standards will apply to HECO’s Kahe, Waiau and Honolulu generating stations unless the utility can demonstrate that at each facility implementation of these standards will result in costs either significantly higher than the EPA considered in establishing the standards for the facility or significantly greater than the benefits of meeting the standards. In either case, the EPA will then make a case-by-case determination of an appropriate performance standard. HECO has until March 2008 to make this showing or demonstrate compliance. HECO has retained a consultant to develop a cost effective compliance strategy and a preliminary assessment of technologies and operational measures. HECO is developing a monitoring program and plans to perform a cost-benefit analysis to demonstrate that HECO’s existing intake systems have minimal environmental impacts, which demonstration would exempt HECO from the standards. Concurrently, HECO will evaluate alternative compliance mechanisms allowed by the rule, some of which could entail significant capital expenditures to implement.

State of Hawaii, ex rel., Bruce R. Knapp, Qui Tam Plaintiff, and Beverly Perry, on behalf of herself and all others similarly situated, Class Plaintiff, vs. The AES Corporation, AES Hawaii, Inc., HECO and HEl

In April 2002, HECO and HEI were served with an amended complaint filed in the First Circuit Court of Hawaii alleging that the State of Hawaii and HECO’s other customers had been overcharged for electricity by over $1 billion since September 1992 due to alleged excessive prices in the PUC-approved amended PPA between HECO and AES Hawaii, Inc. The PUC proceedings in which the amended PPA was approved addressed a number of issues, including whether the terms and conditions of the PPA were reasonable.

As a result of rulings by the First Circuit Court in 2003, all claims for relief and causes of action in the amended complaint were dismissed. In October 2003, plaintiff Beverly Perry filed a notice of appeal on the grounds that the Circuit Court erred in its reliance on the doctrine of primary jurisdiction and the statute of limitations. A decision is pending from the Hawaii Supreme Court. In the opinion of management, the ultimate disposition of this matter will not have a material adverse effect on the Company’s or HECO’s consolidated financial position, results of operations or liquidity.

Collective bargaining agreements

Approximately 58% of the electric utilities’ employees are members of the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260, Unit 8, which is the only union representing employees of the Company. The current collective bargaining and benefit agreements cover a four-year term, from November 1, 2003 to October 31, 2007, and provide for non-compounded wage increases (3% on November 1, 2003; 1.5% on November 1, 2004, May 1, 2005, November 1, 2005 and May 1, 2006; and 3% on November 1, 2006).

(6) Cash flows

Supplemental disclosures of cash flow information

For the three months ended March 31, 2006 and 2005, HECO and its subsidiaries paid interest amounting to $7.6 million and $7.7 million, respectively.

For the three months ended March 31, 2006 and 2005, HECO and its subsidiaries paid income taxes amounting to $4.9 million and $3.0 million, respectively.

Supplemental disclosure of noncash activities

The allowance for equity funds used during construction, which was charged to construction in progress as part of the cost of electric utility plant, amounted to $1.5 million and $1.1 million for the three months ended March 31, 2006 and 2005, respectively.

(7) Recent accounting pronouncements and interpretations

For a discussion of recent accounting pronouncements and interpretations regarding other-than-temporary impairment and its application to certain investments and accounting changes and error corrections, see Note 9 of HEI’s “Notes to Consolidated Financial Statements.”

Determining the variability to be considered in applying FIN 46R

In April 2006, the FASB issued FSP FIN 46R-6, “Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R).” This FSP provides guidance in applying FIN 46R, “Consolidation of Variable Interest Entities.” The variability that is considered can affect the determination of whether an entity is a VIE; which party, if any, is the primary beneficiary of the VIE; and calculations of expected losses and expected residual returns. A company is required to apply the guidance in the FSP prospectively to all entities (including newly created entities) with which that company first becomes involved and to all entities previously required to be analyzed under FIN 46R when a “reconsideration event” has occurred beginning the first day of the first reporting period beginning after June 15, 2006. Because the impact of adopting the provisions of FSP FIN 46R-6 will be dependent on future events and circumstances, management cannot predict such impact.

(8) Income taxes

At March 31, 2006, $0.2 million, net of tax effects, was reserved for unresolved tax issues and related interest. Although not probable, adverse developments on unresolved issues could result in additional charges to net income in the future. Based on information currently available, HECO and its subsidiaries believe they have adequately provided for unresolved income tax issues with federal and state tax authorities and related interest, and that the ultimate resolution of tax issues for all open tax periods will not have a material adverse effect on HECO’s consolidated results of operations, financial condition or liquidity.

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


	Three months ended March 31
(in thousands)	2006			2005
Operating income from regulated and nonregulated activities before income taxes (per HEI consolidated statements of income)	$	45,580		$	31,606
Deduct:
Income taxes on regulated activities		(13,224	)		(7,738	)
Revenues from nonregulated activities		(1,085	)		(1,085	)
Add:
Expenses from nonregulated activities		291			282

Operating income from regulated activities after income taxes (per HECO consolidated statements of income)	$	31,562		$	23,065

(10) Credit agreement

Effective April 3, 2006, HECO entered into a revolving unsecured credit agreement establishing a line of credit facility of $175 million with a syndicate of eight financial institutions. The agreement has an initial term which expires on March 29, 2007, but its term will automatically extend to 5 years if the longer-term agreement is approved by the PUC. Any draws on the facility bear interest at the “Adjusted LIBO Rate” plus 40 basis points or the greater of (a) the “Prime Rate” and (b) the sum of the “Federal Funds Rate” plus 50 basis points, as defined in the agreement. Annual fees on the undrawn commitments are 8 basis points. The agreement contains provisions for revised pricing in the event of a ratings change and customary conditions that must be met in order to draw on it, including compliance with several covenants. In addition to customary defaults, if HECO fails to maintain a “Consolidated Capitalization Ratio” (equity) of at least 35%, as defined in its agreement; if HECO’s as well as any of its subsidiaries’ guarantee of additional indebtedness of the subsidiaries would cause the subsidiary’s Consolidated Subsidiary Funded Debt to Capitalization Ratio to exceed 65%, as defined in its agreement; or if HECO fails to meet other requirements, an event of default would result.

This facility is maintained to support the issuance of commercial paper, but also may be drawn for capital expenditures and general corporate purposes. This facility replaced HECO’s six bilateral bank lines of credit totaling $175 million, which were terminated concurrently with the effectiveness of the new syndicated facility. HECO expects to file with the PUC in the second quarter of 2006 an application seeking approval to extend the termination date of this credit agreement from March 29, 2007, to March 31, 2011. As of May 1, 2006, the $175 million of credit facilities were undrawn.

(11) Consolidating financial information

HECO is not required to provide separate financial statements and 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. Also, see Note 2. 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.

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

March 31, 2006


(in thousands)	HECO			HELCO		MECO		RHI	Reclassi-fications and elimina- tions		HECO consoli- dated
Assets
Utility plant, at cost
Land	$	25,853		3,018		4,317		—	—		$	33,188
Plant and equipment		2,359,463		774,087		682,520		—	—			3,816,070
Less accumulated depreciation		(911,828	)	(282,023	)	(288,744	)	—	—			(1,482,595	)
Plant acquisition adjustment, net		—		—		132		—	—			132
Construction in progress		73,819		12,686		37,025		—	—			123,530

Net utility plant		1,547,307		507,768		435,250		—	—			2,490,325

Investment in subsidiaries, at equity		386,004		—		—		—	(386,004	)		—

Current assets
Cash and equivalents		1,504		3		290		87	—			1,884
Advances to affiliates		49,600		—		750		—	(50,350	)		—
Customer accounts receivable, net		75,426		19,917		16,827		—	—			112,170
Accrued unbilled revenues, net		55,860		13,499		12,049		—	—			81,408
Other accounts receivable, net		9,683		538		320		—	(385	)		10,156
Fuel oil stock, at average cost		70,930		8,557		13,796		—	—			93,283
Materials and supplies, at average cost		14,707		3,545		10,543		—	—			28,795
Prepaid pension benefit cost		78,964		14,843		7,571		—	—			101,378
Other		6,533		380		485		—	—			7,398

Total current assets		363,207		61,282		62,631		87	(50,735	)		436,472

Other long-term assets
Regulatory assets		82,430		14,236		14,772		—	—			111,438
Unamortized debt expense		9,657		2,336		2,186		—	—			14,179
Other		17,244		3,312		3,703		—	—			24,259

Total other long-term assets		109,331		19,884		20,661		—	—			149,876

	$	2,405,849		588,934		518,542		87	(436,739	)	$	3,076,673

Capitalization and liabilities
Capitalization
Common stock equity	$	1,046,607		189,919		196,014		71	(386,004	)	$	1,046,607
Cumulative preferred stock–not subject to mandatory redemption		22,293		7,000		5,000		—	—			34,293
Long-term debt, net		481,159		131,018		153,864		—	—			766,041

Total capitalization		1,550,059		327,937		354,878		71	(386,004	)		1,846,941

Current liabilities
Short-term borrowings–nonaffiliates		145,157		—		—		—	—			145,157
Short-term borrowings–affiliate		750		49,600		—		—	(50,350	)		—
Accounts payable		85,186		17,726		12,553		—	—			115,465
Interest and preferred dividends payable		9,819		1,907		2,918		—	(203	)		14,441
Taxes accrued		70,119		20,403		23,589		—	—			114,111
Other		20,468		3,806		7,653		16	(182	)		31,761

Total current liabilities		331,499		93,442		46,713		16	(50,735	)		420,935

Deferred credits and other liabilities
Deferred income taxes		158,358		24,550		21,064		—	—			203,972
Regulatory liabilities		152,878		41,211		30,509		—	—			224,598
Unamortized tax credits		31,717		12,788		11,737		—	—			56,242
Other		21,173		32,691		9,429		—	—			63,293

Total deferred credits and other liabilities		364,126		111,240		72,739		—	—			548,105

Contributions in aid of construction		160,165		56,315		44,212		—	—			260,692

	$	2,405,849		588,934		518,542		87	(436,739	)	$	3,076,673

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

December 31, 2005


(in thousands)	HECO			HELCO		MECO		RHI	Reclassi- fications and eliminations		HECO consolidated
Assets
Utility plant, at cost
Land	$	25,699		3,018		4,317		—	—		$	33,034
Plant and equipment		2,304,142		766,714		678,530		—	—			3,749,386
Less accumulated depreciation		(898,351	)	(275,444	)	(282,742	)	—	—			(1,456,537	)
Plant acquisition adjustment, net		—		—		145		—	—			145
Construction in progress		108,060		11,414		28,282		—	—			147,756

Net utility plant		1,539,550		505,702		428,532		—	—			2,473,784

Investment in subsidiaries, at equity		383,715		—		—		—	(383,715	)		—

Current assets
Cash and equivalents		8		3		4		128	—			143
Advances to affiliates		49,700		—		5,250		—	(54,950	)		—
Customer accounts receivable, net		81,870		21,652		20,373		—	—			123,895
Accrued unbilled revenues, net		62,701		14,675		13,945		—	—			91,321
Other accounts receivable, net		10,212		2,772		1,185		—	592			14,761
Fuel oil stock, at average cost		64,309		7,868		13,273		—	—			85,450
Materials & supplies, at average cost		14,128		3,204		9,642		—	—			26,974
Prepaid pension benefit cost		82,497		15,388		8,433		—	—			106,318
Other		7,485		541		558		—	—			8,584

Total current assets		372,910		66,103		72,663		128	(54,358	)		457,446

Other long-term assets
Regulatory assets		81,682		14,596		14,440		—	—			110,718
Unamortized debt expense		9,778		2,362		2,221		—	—			14,361
Other		17,816		3,696		3,640		—	—			25,152

Total other long-term assets		109,276		20,654		20,301		—	—			150,231

	$	2,405,451		592,459		521,496		128	(438,073	)	$	3,081,461

Capitalization and liabilities
Capitalization
Common stock equity	$	1,039,259		189,407		194,190		118	(383,715	)	$	1,039,259
Cumulative preferred stock–not subject to mandatory redemption		22,293		7,000		5,000		—	—			34,293
Long-term debt, net		481,132		131,009		153,852		—	—			765,993

Total capitalization		1,542,684		327,416		353,042		118	(383,715	)		1,839,545

Current liabilities
Short-term borrowings–nonaffiliates		136,165		—		—		—	—			136,165
Short-term borrowings–affiliate		5,250		49,700		—		—	(54,950	)		—
Accounts payable		86,843		19,503		15,855		—	—			122,201
Interest and preferred dividends payable		7,217		1,311		1,664		—	(202	)		9,990
Taxes accrued		84,054		24,252		25,277		—	—			133,583
Other		24,971		3,566		7,791		10	794			37,132

Total current liabilities		344,500		98,332		50,587		10	(54,358	)		439,071

Deferred credits and other liabilities
Deferred income taxes		160,351		25,147		22,876		—	—			208,374
Regulatory liabilities		148,898		40,535		29,771		—	—			219,204
Unamortized tax credits		31,209		12,693		11,425		—	—			55,327
Other		21,522		31,781		10,374		—	—			63,677

Total deferred credits and other liabilities		361,980		110,156		74,446		—	—			546,582

Contributions in aid of construction		156,287		56,555		43,421		—	—			256,263

	$	2,405,451		592,459		521,496		128	(438,073	)	$	3,081,461

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Three months ended March 31, 2006


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Operating revenues	$	318,345		79,451		76,175		—		—		$	473,971

Operating expenses
Fuel oil		115,735		20,102		39,501		—		—			175,338
Purchased power		85,454		28,046		4,220		—		—			117,720
Other operation		28,201		7,252		6,566		—		—			42,019
Maintenance		10,557		3,616		2,879		—		—			17,052
Depreciation		18,693		7,431		6,409		—		—			32,533
Taxes, other than income taxes		29,896		7,403		7,224		—		—			44,523
Income taxes		9,057		1,171		2,996		—		—			13,224

		297,593		75,021		69,795		—		—			442,409

Operating income		20,752		4,430		6,380		—		—			31,562

Other income
Allowance for equity funds used during construction		1,077		40		431		—		—			1,548
Equity in earnings of subsidiaries		6,657		—		—		—		(6,657	)		—
Other, net		1,241		70		227		(47	)	(582	)		909

		8,975		110		658		(47	)	(7,239	)		2,457

Income (loss) before interest and other charges		29,727		4,540		7,038		(47	)	(7,239	)		34,019

Interest and other charges
Interest on long-term debt		6,743		1,808		2,227		—		—			10,778
Amortization of net bond premium and expense		339		100		104		—		—			543
Other interest charges		1,870		582		43		—		(582	)		1,913
Allowance for borrowed funds used during construction		(483	)	(19	)	(200	)	—		—			(702	)
Preferred stock dividends of subsidiaries		—		—		—		—		229			229

		8,469		2,471		2,174		—		(353	)		12,761

Income (loss) before preferred stock dividends of HECO		21,258		2,069		4,864		(47	)	(6,886	)		21,258
Preferred stock dividends of HECO		270		134		95		—		(229	)		270

Net income (loss) for common stock	$	20,988		1,935		4,769		(47	)	(6,657	)	$	20,988

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Retained Earnings (unaudited)

Three months ended March 31, 2006


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Retained earnings, beginning of period	$	654,686		88,763		99,269		(363	)	(187,669	)	$	654,686
Net income (loss) for common stock		20,988		1,935		4,769		(47	)	(6,657	)		20,988
Common stock dividends		(13,640	)	(1,423	)	(2,945	)	—		4,368			(13,640	)

Retained earnings, end of period	$	662,034		89,275		101,093		(410	)	(189,958	)	$	662,034

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Three months ended March 31, 2005


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Operating revenues	$	246,128		63,865		63,697		—		—		$	373,690

Operating expenses
Fuel oil		70,884		15,307		29,435		—		—			115,626
Purchased power		78,226		19,782		3,208		—		—			101,216
Other operation		27,695		6,543		7,078		—		—			41,316
Maintenance		11,872		3,233		2,833		—		—			17,938
Depreciation		17,746		6,804		6,270		—		—			30,820
Taxes, other than income taxes		23,828		6,052		6,091		—		—			35,971
Income taxes		3,732		1,513		2,493		—		—			7,738

		233,983		59,234		57,408		—		—			350,625

Operating income		12,145		4,631		6,289		—		—			23,065

Other income
Allowance for equity funds used during construction		911		33		143		—		—			1,087
Equity in earnings of subsidiaries		6,393		—		—		—		(6,393	)		—
Other, net		1,033		59		66		(46	)	(269	)		843

		8,337		92		209		(46	)	(6,662	)		1,930

Income (loss) before interest and other charges		20,482		4,723		6,498		(46	)	(6,662	)		24,995

Interest and other charges
Interest on long-term debt		6,830		1,839		2,240		—		—			10,909
Amortization of net bond premium and expense		348		101		107		—		—			556
Other interest charges		1,003		280		59		—		(269	)		1,073
Allowance for borrowed funds used during construction		(354	)	(11	)	(62	)	—		—			(427	)
Preferred stock dividends of subsidiaries		—		—		—		—		229			229

		7,827		2,209		2,344		—		(40	)		12,340

Income (loss) before preferred stock dividends of HECO		12,655		2,514		4,154		(46	)	(6,622	)		12,655
Preferred stock dividends of HECO		270		134		95		—		(229	)		270

Net income (loss) for common stock	$	12,385		2,380		4,059		(46	)	(6,393	)	$	12,385

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Retained Earnings (unaudited)

Three months ended March 31, 2005


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Retained earnings, beginning of period	$	632,779		85,861		94,492		(187	)	(180,166	)	$	632,779
Net income (loss) for common stock		12,385		2,380		4,059		(46	)	(6,393	)		12,385
Common stock dividends		(9,933	)	(1,676	)	(2,795	)	—		4,471			(9,933	)

Retained earnings, end of period	$	635,231		86,565		95,756		(233	)	(182,088	)	$	635,231

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Three months ended March 31, 2006


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Cash flows from operating activities
Income (loss) before preferred stock dividends of HECO	$	21,258		2,069		4,864		(47	)	(6,886	)	$	21,258
Adjustments to reconcile income (loss) before preferred stock dividends of HECO to net cash provided by (used in) operating activities
Equity in earnings		(6,682	)	—		—		—		6,657			(25	)
Common stock dividends received from subsidiaries		4,393		—		—		—		(4,368	)		25
Depreciation of property, plant and equipment		18,693		7,431		6,409		—		—			32,533
Other amortization		884		225		569		—		—			1,678
Deferred income taxes		(1,993	)	(597	)	(1,800	)	—		—			(4,390	)
Tax credits, net		720		142		367		—		—			1,229
Allowance for equity funds used during construction		(1,077	)	(40	)	(431	)	—		—			(1,548	)
Changes in assets and liabilities
Decrease in accounts receivable		6,973		3,969		4,411		—		977			16,330
Decrease in accrued unbilled revenues		6,841		1,176		1,896		—		—			9,913
Increase in fuel oil stock		(6,621	)	(689	)	(523	)	—		—			(7,833	)
Increase in materials and supplies		(579	)	(341	)	(901	)	—		—			(1,821	)
Decrease in prepaid pension benefit cost		3,533		545		862		—		—			4,940
Decrease (increase) in regulatory assets		(673	)	195		(641	)	—		—			(1,119	)
Decrease in accounts payable		(1,657	)	(1,777	)	(3,302	)	—		—			(6,736	)
Decrease in taxes accrued		(13,935	)	(3,849	)	(1,688	)	—		—			(19,472	)
Changes in other assets and liabilities		2,736		2,434		(207	)	6		(977	)		3,992

Net cash provided by (used in) operating activities		32,814		10,893		9,885		(41	)	(4,597	)		48,954

Cash flows from investing activities
Capital expenditures		(22,109	)	(9,554	)	(11,416	)	—		—			(43,079	)
Contributions in aid of construction		5,837		429		357		—		—			6,623
Advances to affiliates		100		—		4,500		—		(4,600	)		—
Other		108		—		—		—		—			108

Net cash used in investing activities		(16,064	)	(9,125	)	(6,559	)	—		(4,600	)		(36,348	)

Cash flows from financing activities
Common stock dividends		(13,640	)	(1,423	)	(2,945	)	—		4,368			(13,640	)
Preferred stock dividends		(270	)	(134	)	(95	)	—		229			(270	)
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		4,492		(100	)	—		—		4,600			8,992
Other		(5,836	)	(111	)	—		—		—			(5,947	)

Net cash used in financing activities		(15,254	)	(1,768	)	(3,040	)	—		9,197			(10,865	)

Net increase (decrease) in cash and equivalents		1,496		—		286		(41	)	—			1,741
Cash and equivalents, beginning of period		8		3		4		128		—			143

Cash and equivalents, end of period	$	1,504		3		290		87		—		$	1,884

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Three months ended March 31, 2005


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and eliminations		HECO consolidated
Cash flows from operating activities
Income before preferred stock dividends of HECO	$	12,655		2,514		4,154		(46	)	(6,622	)	$	12,655
Adjustments to reconcile income (loss) before preferred stock dividends of HECO to net cash provided by (used in) operating activities
Equity in earnings		(6,418	)	—		—		—		6,393			(25	)
Common stock dividends received from subsidiaries		4,496		—		—		—		(4,471	)		25
Depreciation of property, plant and equipment		17,746		6,804		6,270		—		—			30,820
Other amortization		978		329		916		—		—			2,223
Deferred income taxes		(948	)	336		(786	)	—		—			(1,398	)
Tax credits, net		488		141		64		—		—			693
Allowance for equity funds used during construction		(911	)	(33	)	(143	)	—		—			(1,087	)
Changes in assets and liabilities
Decrease in accounts receivable		10,362		1,497		2,655		—		995			15,509
Decrease in accrued unbilled revenues		10,293		1,380		1,854		—		—			13,527
Decrease (increase) in fuel oil stock		(8,198	)	2,214		(890	)	—		—			(6,874	)
Increase in materials and supplies		(1,148	)	(33	)	(270	)	—		—			(1,451	)
Decrease in prepaid pension benefit cost		1,104		281		516		—		—			1,901
Decrease (increase) in regulatory assets		40		181		(500	)	—		—			(279	)
Increase (decrease) in accounts payable		(7,253	)	(3,078	)	824		—		—			(9,507	)
Decrease in taxes accrued		(17,889	)	(3,411	)	(2,219	)	—		—			(23,519	)
Changes in other assets and liabilities		832		(612	)	1,227		17		(995	)		469

Net cash provided by (used in) operating activities		16,229		8,510		13,672		(29	)	(4,700	)		33,682

Cash flows from investing activities
Capital expenditures		(21,864	)	(10,808	)	(5,085	)	—		—			(37,757	)
Contributions in aid of construction		820		638		413		—		—			1,871
Advances to (repayments from) affiliates		(3,450	)	—		500		—		2,950			—
Other		1,423		—		—		—		—			1,423

Net cash used in investing activities		(23,071	)	(10,170	)	(4,172	)	—		2,950			(34,463	)

Cash flows from financing activities
Common stock dividends		(9,933	)	(1,676	)	(2,795	)	—		4,471			(9,933	)
Preferred stock dividends		(270	)	(134	)	(95	)	—		229			(270	)
Proceeds from issuance of long-term debt		41,485		5,000		2,000		—		—			48,485
Repayment of long-term debt		(40,000	)	(5,000	)	(2,000	)	—		—			(47,000	)
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		21,502		3,450		—		—		(2,950	)		22,002
Other		(4,873	)	20		—		—		—			(4,853	)

Net cash provided by (used in) financing activities		7,911		1,660		(2,890	)	—		1,750			8,431

Net increase (decrease) in cash and equivalents		1,069		—		6,610		(29	)	—			7,650
Cash and equivalents, beginning of period		9		3		17		298		—			327

Cash and equivalents, end of period	$	1,078		3		6,627		269		—		$	7,977

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” in HEI’s 2005 Form 10-K and should be read in conjunction with the annual (as of and for the year ended December 31, 2005) and quarterly (as of and for the three months ended March 31, 2006) consolidated financial statements of HEI and HECO and accompanying notes.

HEI CONSOLIDATED

RESULTS OF OPERATIONS


	Three months ended March 31,				% change	Primary reason(s) for significant change*
(in thousands, except per share amounts)	2006		2005		% change	Primary reason(s) for significant change*
Revenues	$	574,962	$	472,628	22	Increase for the electric utility and bank segments, slightly offset by a decrease for the “other” segment

Operating income		69,151		56,671	22	Increase for the electric utility and the “other” segments, partly offset by a decrease for the bank segment

Net income		32,337		24,095	34	Higher operating income and AFUDC, and lower effective income tax rate, partly offset by higher “interest expense—other than bank”

Basic earnings per common share	$	0.40	$	0.30	33	Higher net income

Weighted-average number of common shares outstanding		80,981		80,701	—	Issuances of shares under Company compensatory plans

*	Also, see segment discussions which follow.

Dividends

On May 2, 2006, HEI’s Board maintained the quarterly dividend of $0.31 per common share. The payout ratio for 2005 and the first quarter of 2006 was 79% and 78% (payout ratio of 78% and 78% based on income from continuing operations), respectively. HEI’s Board and management believe that HEI should achieve a 65% payout ratio on a sustainable basis and that cash flows should support an increase before it considers increasing the common stock dividend above its current level.

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), U.S. Census Bureau and Bloomberg).

Because HEI’s core businesses provide local electric utility and banking services, HEI’s operating results are significantly influenced by the strength of Hawaii’s economy. The state’s economic growth, which is fueled by the two largest components of Hawaii’s economy—tourism and the federal government, was estimated at 3.8% for 2005 and forecast at a moderate 3.0% for 2006 by DBEDT.

According to the latest available data, Hawaii ranked fifth among the states in its receipt of federal government expenditures per capita. For the federal fiscal year ended September 30, 2004 (latest available data), total federal government expenditures in Hawaii, including military expenditures, were $12.2 billion or $9,651 per capita, increasing 8% and 7%, respectively, over fiscal year 2003. Military spending, which is 39% of federal expenditures in Hawaii, increased 6% in 2004 compared to 2003.

Tourism is widely acknowledged as a significant component of Hawaii’s economy. 2005 was a record year for tourism in Hawaii, with visitor days exceeding the 2004 record by 6.6%. Visitor expenditures were $11.8 billion in 2005, which is an 8.7% increase from 2004. State economists expect continued growth in 2006 with projected increases of 3.1% in visitor days and 4.6% in visitor expenditures. Visitor days through February 2006 were up 3% compared to the same period a year ago.

The real estate and construction industries in Hawaii also influence HEI’s core businesses. The Oahu housing market is stabilizing with sales coming off their record levels and inventory returning to more normal levels. Total sales in the first quarter of 2006 decreased 2.8% compared to the first quarter of 2005, in line with a stabilizing market. The median home price on Oahu reached a record $650,000 in March 2006 compared to the median of $525,500 in March 2005.

The construction industry continues to remain healthy, indicated by a 29% increase in building permits year-to-date through February 2006 compared with the same period last year. Local economists forecast a gradual deceleration of growth in residential construction over the next few years due to declining affordability, rising construction costs and interest rate increases. However, military and commercial construction will be stabilizing factors.

Overall, the outlook for Hawaii’s economy remains positive. However, economic growth is affected by the rate of expansion in the mainland U.S. and Japan economies and the growth in military spending, and is vulnerable to uncertainties in the world’s geopolitical environment.

Management also monitors (1) oil prices because of their impact on the rates the utilities charge for electricity and the potential effect of increased prices of electricity on usage, and (2) interest rates because of their potential impact on ASB’s earnings, HEI’s and HECO’s cost of capital, pension costs and HEI’s stock price. Inventory levels of crude oil rose to their highest level in April 2006 since 1998. Geopolitical fallout from Iran’s renewed nuclear program and increasing risks of supply disruption, however, continued to push crude oil prices higher. On May 1, 2006, crude oil futures closed at $73.70 per barrel.

Long-term interest rates were flat in the first quarter of 2006 with the 10-year Treasury yield rising to over 5% for the first time in April 2006 since June 2002. At the end of March 2006, the yield curve began to slope upward which may signal concern for future inflation. The spread between the 10-year and 2-year Treasuries was 0.19% as of May 1, 2006, compared to a spread of (0.02)% as of December 31, 2005.

“Other” segment


	Three months ended March 31,						% change	Primary reason(s) for significant change
(in thousands)	2006			2005			% change	Primary reason(s) for significant change
Revenues	$	(98	)	$	629		NM	Loss of $0.6 million (net unrealized and realized) on Hoku shares (see Note 11 of HEI’s “Notes to Consolidated Financial Statements”)

Operating loss		(3,444	)		(3,888	)	NM	Lower stock-based compensation expense and non-officer bonuses, partly offset by loss on Hoku shares and higher retirement benefit expense

Net loss		(5,478	)		(6,051	)	NM	See explanation for operating loss and lower tax expense (the first quarter of 2005 included higher tax expense due to limits on the deductibility of executive compensation)

NM	Not meaningful.

The “other” business segment includes results of operations of HEI Investments, Inc. (HEIII), a company primarily holding investments in leveraged leases; Pacific Energy Conservation Services, Inc., a contract services company primarily providing windfarm operational and maintenance services to an affiliated electric utility; HEI Properties, Inc. (HEIPI), a company holding passive investments; Hycap Management, Inc. (which is in dissolution); The Old Oahu Tug Service, Inc., which was previously a maritime freight transportation company that ceased operations in 1999 and now is largely inactive; HEI and HEIDI, which are both holding companies; and eliminations of intercompany transactions.

Commitments and contingencies

See Note 7 of HEI’s “Notes to Consolidated Financial Statements.”

Recent accounting pronouncements and interpretations

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

FINANCIAL CONDITION

Liquidity and capital resources

HEI believes that its ability, and that of its subsidiaries, to generate cash, both internally from electric utility and banking operations and externally from issuances of equity and debt securities, commercial paper, lines of credit and bank borrowings, is adequate to maintain sufficient liquidity to fund the Company’s capital expenditures and investments and to cover debt, retirement benefits and other cash requirements in the foreseeable future.

The consolidated capital structure of HEI (excluding ASB’s deposit liabilities, securities sold under agreements to repurchase and advances from the Federal Home Loan Bank (FHLB) of Seattle) was as follows:


(in millions)	March 31, 2006				December 31, 2005
Short-term borrowings	$	183	7	%	$	142	6	%
Long-term debt, net		1,133	44			1,143	45
Preferred stock of subsidiaries		34	1			34	1
Common stock equity		1,211	48			1,217	48

	$	2,561	100	%	$	2,536	100	%

As of May 1, 2006, the Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HEI securities were as follows:


	S&P	Moody’s
Commercial paper	A-2	P-2
Medium-term notes	BBB	Baa2

The above ratings are not recommendations to buy, sell or hold any securities; such ratings may be subject to revision or withdrawal at any time by the rating agencies; and each rating should be evaluated independently of any other rating.

HEI’s overall S&P corporate credit rating is BBB/Negative/A-2.

As of March 31, 2006, $96 million of debt, equity and/or other securities were available for offering by HEI under an omnibus shelf registration and an additional $150 million principal amount of Series D notes were available for offering by HEI under its registered medium-term note program.

HEI utilizes short-term debt, principally commercial paper, to support normal operations and for other temporary requirements. HEI also periodically makes short-term loans to HECO to meet HECO’s cash requirements, including for loans by HECO to HELCO and MECO. HEI had an average outstanding balance of commercial paper for the first three months of 2006 of $15 million and had $37 million outstanding as of March 31, 2006. Management believes that if HEI’s commercial paper ratings were to be downgraded, it may be more difficult to sell commercial paper under current market conditions.

Effective April 3, 2006, HEI entered into a revolving unsecured credit agreement establishing a line of credit facility of $100 million, with a letter of credit sub-facility, expiring on March 31, 2011, with a syndicate of eight financial institutions. Any draws on the facility bear interest at the “Adjusted LIBO Rate” plus 50 basis points or the greater of (a) the “Prime Rate” and (b) the sum of the “Federal Funds Rate” plus 50 basis points, as defined in the agreement. Annual fees on undrawn commitments are 10 basis points. The agreement contains provisions for revised pricing in the event of a ratings change. For example, a ratings downgrade of HEI’s Senior Debt Rating (e.g., from BBB/Baa2 to BBB-/Baa3 by Standard & Poor’s (S&P) and Moody’s Investors Service (Moody’s), respectively) would result in a commitment fee increase of 2.5 basis points and an interest rate increase of 10 basis points on any drawn amounts. On the other hand, a ratings upgrade (e.g., from BBB/Baa2 to BBB+/Baa1) would result in a commitment fee

decrease of 2 basis points and an interest rate decrease of 10 basis points on any drawn amounts. The agreement does not contain clauses that would affect access to the lines by reason of a ratings downgrade, nor does it have broad “material adverse change” clauses. However, the agreement does contain customary conditions which must be met in order to draw on it, including compliance with its covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HEI). In addition to customary defaults, HEI’s failure to maintain its financial ratio, as defined in its agreement, or meet other requirements will result in an event of default. For example, under its agreement, it is an event of default if HEI fails to maintain a nonconsolidated “Capitalization Ratio” (funded debt) of 50% or less (Ratio of 27% as of March 31, 2006) and “Consolidated Net Worth” of $850 million (Net Worth of $1.3 billion as of March 31, 2006), if there is a “Change in Control” of HEI, if any event or condition occurs that results in any “Material Indebtedness” of HEI being subject to acceleration prior to its scheduled maturity, if any “Material Subsidiary Indebtedness” actually becomes due prior to its scheduled maturity, or if ASB fails to remain well capitalized and to maintain specified minimum capital ratios.

Also effective April 3, 2006, HEI entered into a $75 million bilateral revolving unsecured credit agreement with Merrill Lynch Bank USA, which expires on December 27, 2006. Any draws on the facility bear interest at the “Adjusted LIBO Rate” plus 57.5 basis points or the greater of (a) the “Prime Rate” and (b) the sum of the “Federal Funds Rate” plus 50 basis points, as defined in the agreement. Under this agreement, a ratings downgrade from BBB/Baa2 to BBB-/Baa3 by S&P and Moody’s, respectively, would result in a 15 basis point increase in interest rates, and a ratings upgrade to BBB+/Baa1 would result in a 7.5 basis point decrease in interest rates. Conditions precedent to drawing on the line and events of default are similar to HEI’s $100 million 5-year revolving unsecured credit agreement.

HEI’s credit facilities, totaling $175 million, will be maintained to support the issuance of commercial paper, but also may be drawn for general corporate purposes. These facilities replaced HEI’s four bilateral bank lines of credit totaling $80 million, which were terminated concurrently with the effectiveness of the new facilities. The Company used the new facilities to support the issuance of commercial paper to refinance its $100 million of Series C medium-term notes, which matured on April 10, 2006. As of May 1, 2006, the $175 million of credit facilities were undrawn.

For the first three months of 2006, net cash provided by operating activities of consolidated HEI was $71 million. Net cash used in investing activities for the same period was $99 million primarily due to a net increase in loans receivable at ASB and HECO’s consolidated capital expenditures. Net cash provided by financing activities during this period was $53 million as a result of several factors, including net increases in deposit liabilities, short-term borrowings and securities sold under agreements to repurchase, partly offset by a net decrease in advances from the FHLB, repayment of long-term debt and the payment of common stock dividends.

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

ELECTRIC UTILITIES

RESULTS OF OPERATIONS


(dollars in thousands, except per barrel amounts)	Three months ended March 31,				% change		Primary reason(s) for significant change
(dollars in thousands, except per barrel amounts)	2006		2005		% change		Primary reason(s) for significant change
Revenues	$	475,056	$	374,775	27		Higher fuel oil and purchased energy fuel costs, the effects of which are generally passed on to customers ($77 million), 1.8% higher KWH sales ($11 million) and interim rate relief ($9 million)
Expenses
Fuel oil		175,338		115,626	52		Higher fuel oil costs and more KWHs generated
Purchased power		117,720		101,216	16		Higher fuel costs, partly offset by lower capacity charges and less KWHs purchased
Other		136,418		126,327	8		Higher depreciation and taxes, other than income taxes
Operating income		45,580		31,606	44		Higher KWH sales and interim rate relief and lower capacity charges, partly offset by higher depreciation and taxes, other than income taxes
Net income		20,988		12,385	69		Higher operating income and AFUDC, partly offset by higher interest expense due to higher short-term borrowings and short-term interest rates
Kilowatthour sales (millions)		2,390		2,347	2		Load growth and, in March 2006, higher humidity, partly offset by cooler weather
Cooling degree days (Oahu)		773		780	(1	)
Fuel oil cost per barrel	$	63.59	$	45.63	39

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

Results – three months ended March 31, 2006

Operating income for the first quarter of 2006 increased 44% from the same period in 2005, but was comparable to the first quarter of 2004 (increasing only 3%). The 44% increase in first quarter 2006 operating income over first quarter 2005 was due primarily to interim rate relief granted by the PUC in late September 2005, higher KWH sales, and lower purchase power capacity charges due primarily to lower availability caused by scheduled major maintenance by an IPP, which was not performed in 2005. KWH sales in the first three months of 2006 increased 1.8% from the same period in 2005, primarily due to new load growth (i.e., increase in number of customers and new construction), and, in March 2006, higher humidity, partly offset by cooler weather. Other operation expense increased 2% primarily due to higher employee retirement benefits expense and higher production operations expense, including rent expense for distributed generation units on Oahu, partly offset by lower other administrative and general expenses. Pension and other postretirement benefit expenses for the electric utilities increased $2.3 million over the same period in 2005 primarily due to the impact of the recognition of asset losses from prior years and the adoption of a 25 basis points lower discount rate as of December 31, 2005 by the HEI Pension Investment Committee. Maintenance expense decreased by 5% due to lower production maintenance expense (primarily due to fewer generating unit overhauls, partly offset by higher steam generation station maintenance) and transmission and distribution maintenance expense (primarily due to lower vegetation management). Higher depreciation expense was attributable to additions to plant in service in 2005 (including HECO’s New Kuahua

Substation, Mokuone Substation 46kV and 12kV line extensions, an office building air conditioning replacement and HELCO’s CT-5 and CT-2 noise mitigation measures).

Although other operation and maintenance (O&M) expenses were relatively flat for the first quarter of 2006 when compared to the same quarter in 2005, the trend of increased O&M expenses is expected to continue in 2006 as the electric utilities expect (1) higher demand side management expenses (that are generally passed on to customers through a surcharge and are being considered in an energy efficiency DSM Docket) and integrated resource planning expenses, (2) higher employee benefit expenses, primarily for retirement benefits, and (3) higher production expenses, primarily to meet higher demand levels and load growth achieved in 2004, sustained in 2005 and continuing in 2006. As a result of load growth on Oahu and other factors, there currently is an increased risk to generation reliability. Existing units are running harder, resulting in more frequent and more extensive maintenance, at times requiring temporary shut downs of these units. Generation reserve margins during peak periods are lower than considered desirable in light of these circumstances. The electric utilities have taken a number of steps to mitigate the risk of outages, including securing additional purchased power, adding distributed generation at some substations and encouraging energy conservation. The marginal costs of supplying growing demand, however, are increasing because of the decreasing reserve margin situation, and the rate of cost increases is not likely to lessen until a proposed new generating unit on Oahu is added in 2009. Increased O&M expense was one of the reasons HECO filed a request with the PUC in November 2004 to increase base rates. In late September 2005, HECO received interim rate relief (see “Most recent rate requests”).

Competition

Although competition in the generation sector in Hawaii has been moderated by the scarcity of generation sites, various permitting processes and lack of interconnections to other electric utilities, HECO and its subsidiaries face competition from IPPs and customer self-generation, with or without cogeneration.

In 1996, the PUC issued an order instituting a proceeding to identify and examine the issues surrounding electric competition and to determine the impact of competition on the electric utility infrastructure in Hawaii. In October 2003, the PUC closed the competition proceeding and opened investigative proceedings on two specific issues (competitive bidding and DG) to move toward a more competitive electric industry environment under cost-based regulation.

Competitive bidding proceeding. The stated purpose of this proceeding is to evaluate competitive bidding as a mechanism for acquiring or building new generating capacity in Hawaii.

The current parties/participants in the proceeding include the Consumer Advocate, HECO, HELCO, MECO, Kauai Island Utility Cooperative and a renewable energy organization. The issues to be addressed in the proceeding include the benefits and impacts of competitive bidding, whether a competitive bidding system should be developed for acquiring or building new generation, and revisions that should be made to integrated resource planning. If it is determined that a competitive bidding system should be developed, issues include how a fair system can be developed that “ensures that competitive benefits result from the system and ratepayers are not placed at undue risk,” what the guidelines and requirements for prospective bidders should be, and how such a system can encourage broad participation. Statements of position by, information requests to, and responses by the parties/participants were filed in March through August 2005. The PUC held panel hearings in December 2005. In the second quarter of 2006, the parties are scheduled to file a proposed competitive bidding framework incorporating areas of agreement in on-going settlement discussions, and briefs addressing any areas of disagreement and post-hearing questions posed by the PUC. Management cannot predict the ultimate outcome of this proceeding or its effect on the ability of the electric utilities to acquire or build additional generating capacity in the future.

Distributed generation proceeding. In October 2003, the PUC opened a DG proceeding to determine DG’s potential benefits to and impact on Hawaii’s electric distribution systems and markets and to develop policies and a framework for DG projects deployed in Hawaii.

On January 27, 2006, the PUC issued its D&O in the DG proceeding. In the D&O, the PUC indicated that its policy is to promote the development of a market structure that assures DG is available at the lowest feasible cost, DG that is economical and reliable has an opportunity to come to fruition and DG that is not cost-effective does not enter the system.

With regard to DG ownership, the D&O affirmed the ability of the electric utilities to procure and operate DG for utility purposes at utility sites. The PUC also indicated its desire to promote the development of a competitive market for customer-sited DG. In weighing the general advantages and disadvantages of allowing a utility to provide DG services on a customer’s site, the PUC found that the “disadvantages outweigh the advantages.” However, the PUC also found that the utility “is the most informed potential provider of DG” and it would not be in the public interest to exclude the HECO Utilities from providing DG services at this early stage of DG market development.

Therefore, the D&O allows the utility to provide DG services on a customer-owned site as a regulated service when (1) the DG resolves a legitimate system need, (2) the DG is the least cost alternative to meet that need, and (3) it can be shown that, in an open and competitive process acceptable to the PUC, the customer operator was unable to find another entity ready and able to supply the proposed DG service at a price and quality comparable to the utility’s offering.

The D&O also requires the electric utilities to establish reliability and safety requirements for DG, establish a non-discriminatory DG interconnection policy, develop a standardized interconnection agreement to streamline the DG application review process, establish standby rates based on unbundled costs associated with providing each service (i.e., generation, distribution, transmission and ancillary services), and establish detailed affiliate requirements should the utility choose to sell DG through an affiliate.

On March 1, 2006, the electric utilities filed a Motion for Clarification and/or Partial Reconsideration (DG Motion) requesting that the PUC clarify how the three conditions under which electric utilities are allowed to provide regulated DG services at customer-owned sites will be administered, in order to better determine the impacts the conditions may have on the electric utilities’ DG plans. On April 6, 2006, the PUC issued its decision on the electric utilities’ DG Motion. The PUC provided clarification to the conditions under which the electric utilities are allowed to provide regulated DG services (e.g., the utilities can use a portfolio perspective— a DG project aggregated with other DG systems and other supply-side and demand-side options—to support a finding that utility-owned customer-sited DG projects fulfill a legitimate system need, and the economic standard of “least cost” in the order means “lowest reasonable cost” consistent with the standard in the IRP framework), and affirmed that the electric utility has the responsibility to demonstrate that it meets all applicable criteria included in the D&O in its application for PUC approval to proceed with a specific DG project. The electric utilities are currently evaluating several potential DG and CHP projects, and if a decision is made to pursue a specific project, an application requesting project approval will be filed with the PUC.

Most recent rate requests

The electric utilities initiate PUC proceedings from time to time to request electric rate increases to cover rising operating costs and the cost of plant and equipment, including the cost of new capital projects to maintain and improve service reliability. As of May 1, 2006, the return on average common equity (ROACE) found by the PUC to be reasonable in the most recent final rate decision for each utility was 11.40% for HECO (D&O issued on December 11, 1995, based on a 1995 test year), 11.50% for HELCO (D&O issued on February 8, 2001, based on a 2000 test year) and 10.94% for MECO (amended D&O issued on April 6, 1999, based on a 1999 test year). However, the ROACE used for purposes of the interim rate increase in HECO’s current rate case was 10.70%. For 2005, the simple average ROACEs (calculated under the rate-making method and reported to the PUC semi-annually) for HECO, HELCO and MECO were 6.92%, 6.86% and 9.81%, respectively. HECO’s actual ROACE is significantly lower than its allowed ROACE primarily because of increased O&M expenses, which are expected to continue and could result in HECO seeking rate relief more often than in the past. The interim rate relief granted to HECO by the PUC in September 2005 (see below) was based in part on increased costs of operating and maintaining HECO’s system. HELCO’s ROACE will continue to be negatively impacted by CT-4 and CT-5 as electric rates will not change for the unit additions until HELCO files a rate increase application (currently planned for spring 2006) and the PUC grants HELCO rate relief.

As of May 1, 2006, the ROR found by the PUC to be reasonable in the most recent final rate decision for each utility was 9.16% for HECO, 9.14% for HELCO and 8.83% for MECO (D&Os noted above). However, the ROR used for purposes of the interim D&O in the current HECO rate case is 8.66%. For 2005, the simple average RORs

(calculated under the rate-making method and reported to the PUC semi-annually) for HECO, HELCO and MECO were 6.20%, 6.08% and 8.21%, respectively.

If the utilities are required to record significant charges to accumulated other comprehensive income (AOCI) related to a minimum liability for retirement benefits, the electric utilities’ RORs would increase and could impact the rates the electric utilities are allowed to charge, which may ultimately result in reduced revenues and lower earnings. In December 2005, the electric utilities submitted a request to the PUC for approval to record as a regulatory asset and include in rate base the amount that would otherwise be charged to AOCI and reduce stockholder’s equity. If their request is granted, the electric utilities’ stockholder’s equity and rate base would not be affected since charges to AOCI would not be made to record a minimum pension liability and their returns on equity and rate base and financial ratios would thus not be adversely affected.

HECO. In November 2004, HECO filed a request with the PUC to increase base rates 9.9%, or $99 million in annual base revenues, based on a 2005 test year, a 9.11% return on rate base and an 11.5% return on average common equity. The requested increase included transferring the cost of existing DSM programs from a surcharge line item on electric bills into base electricity charges. HECO also requested approval and/or modification of its existing and proposed DSM programs, and associated utility incentive mechanism. Excluding the surcharge transfer amount, the requested net increase to customers was 7.3%, or $74 million.

In March 2005, the PUC issued a bifurcation order separating HECO’s requests for approval and/or modification of its existing and proposed DSM programs from the rate case proceeding into a new docket (EE DSM Docket). The preliminary issues identified by the PUC for the new EE DSM Docket include (1) whether, and if so, what, energy efficiency goals should be established, (2) whether the proposed and/or other DSM programs will achieve the established energy efficiency goals and be implemented in a cost-effective manner, (3) what market structures are most appropriate for providing these or other DSM programs, and (4) for utility-incurred costs, what cost recovery mechanisms and cost levels are appropriate. The original parties/participants in this docket included HECO, the Consumer Advocate, the DOD, the County of Maui, two renewable energy organizations, an energy efficiency organization, and an environmental organization. In June 2005, however, the PUC, on its own initiative, included HELCO, MECO, Kauai Island Utility Cooperative and The Gas Company as parties to the docket (and in September 2005 made the County of Kauai a participant), provided their participation is limited solely to the issues dealing with statewide energy policies. In March 2006, the PUC informed the parties that it would involve the EPA and its consultants in an advisory capacity in this docket and amended the procedural schedule to include the submission of reports by the EPA and its consultants on the issues in this proceeding. Simultaneous statements of position are to be filed by all parties in June 2006. Panel hearings will be held in August 2006. See “Other regulatory matters—Demand-side management programs” below for additional information on this docket and a discussion of the PUC’s Interim Decision and Order issued on April 26, 2006.

In September 2005, HECO, the Consumer Advocate and the DOD reached agreement among themselves on most of the issues in the rate case proceeding, subject to PUC approval. The remaining significant issue among the parties was the appropriateness of including in rate base approximately $50 million related to HECO’s prepaid pension asset, net of deferred income taxes.

Later in the same month, the PUC issued its interim D&O (with tariff changes effective September 28, 2005 and amounts collected refundable, with interest, to ratepayers to the extent they exceed the amount approved in the final D&O). For purposes of the interim D&O, the PUC included HECO’s prepaid pension asset in rate base (with a rate increase impact of approximately $7 million).

The following amounts were included in HECO’s rebuttal, the Consumer Advocate’s and the DOD’s testimonies and exhibits (as adjusted to exclude the transferred surcharge amount of $12 million); the settlement agreement; and the PUC’s interim D&O:


	Pre-Settlement
(dollars in millions)	HECO rebuttal			Consumer Advocate			Department of Defense			HECO (per settlement)			Interim increase¹
Net additional revenues ²	$	51		$	11		$	7		$	42		$	41
ROACE		11	%		8.5-10	%		9	%		10.7	%		10.7	%
ROR		8.83	%		7.85	%		7.71	%		8.66	%		8.66	%
Average rate base	$	1,109		$	1,065		$	1,062		$	1,109		$	1,109

¹	Effective September 28, 2005, subject to refund with interest pending the final outcome of the case.

²	Excludes $12 million transferred from a surcharge to base rates for existing energy efficiency programs.

The adoption of revenue, expense, rate base and cost of capital amounts (including the ROACE and ROR) for purposes of an interim rate increase does not commit the PUC to accept any such amounts in its final D&O.

HELCO. In May 2006, HELCO filed a request with the PUC to increase base rates by $30 million, or 9.24% in annual base revenues, based on a 2006 test year and an 8.65% return on rate base (which includes an 11.25% return on common equity and a $369 million average rate base). HELCO’s application includes a proposed new tiered rate structure, which would enable most residential users to see smaller increases in the range of 3% to 8%. The tiered rate structure is designed to minimize the increase for residential customers using less electricity and is expected to encourage customers to take advantage of solar water heating programs and other energy management options. The proposed rate increase would pay for improvements made to increase reliability, including transmission and distribution line improvements and the two generating units at the Keahole power plant (CT-4 and CT-5). The earliest that any increase, if allowed, may go into effect is expected to be in early 2007.

Other regulatory matters

For information about the “Avoided cost generic docket,” see page 67 of HEI’s 2005 Form 10-K.

Demand-side management programs. The following updates the “Demand-side management programs” discussions on pages 66 to 67 of HEI’s 2005 Form 10-K.

In October 2001, HECO and the Consumer Advocate finalized agreements, subject to PUC approval, for the continuation of HECO’s three commercial and industrial DSM programs and two residential DSM programs until HECO’s next rate case. These agreements were in lieu of HECO continuing to seek approval of new 5-year DSM programs and provided that DSM programs to be in place after HECO’s next rate case would be determined as part of the case. Under the agreements, HECO agreed to cap the recovery of lost margins and shareholder incentives if such recovery would cause HECO to exceed its current “authorized return on rate base” (i.e. the rate of return on rate base found by the PUC to be reasonable in the most recent rate case for HECO). HECO also agreed it would not pursue the continuation of lost margins recovery and shareholder incentives through a surcharge mechanism in future rate cases. At the time of the agreement, HECO indicated to the Consumer Advocate that it plans to seek alternative incentive mechanisms for DSM programs in its rate case. In November 2001, the PUC issued orders that, subject to certain reporting requirements and other conditions, approved the agreements regarding the temporary continuation of HECO’s five existing DSM programs until HECO’s next rate case.

In November 2004, HECO filed a request for a rate increase and approval and/or modification of its existing and proposed DSM programs, and associated utility incentive mechanism. In March 2005, the PUC issued a bifurcation order separating HECO’s requests for approval and/or modification of its existing and proposed DSM programs from the rate case proceeding into a new docket. The bifurcation order allowed HECO to temporarily continue, in the manner currently employed, its existing three commercial and industrial DSM programs and two residential DSM programs, until further order by the PUC.

As a result of the bifurcation order in HECO’s rate case, HECO has been continuing its existing DSM programs and cost recovery mechanisms, including the recovery of program costs, and shareholder incentives and lost margins for its energy efficiency DSM programs through a surcharge mechanism, pending the resolution of the EE DSM Docket. In the EE DSM Docket, HECO requested PUC approval, on an interim basis, for certain modifications to its existing energy efficiency DSM programs and a new interim DSM program (Interim DSM Proposals). HECO did not request shareholder incentives and lost margins for its proposed new interim DSM program, but did so for the modifications to its existing energy efficiency programs. On January 10, 2006, the Consumer Advocate filed comments on HECO’s Interim DSM Proposals, which included an objection to the continued recovery of shareholder incentives and lost margins for the existing energy efficiency DSM programs as well as for the modifications. HECO filed its response to the Consumer Advocate’s comments on January 31, 2006, reaffirming its position that the continuation of shareholder incentives and lost margins for its existing energy efficiency DSM programs is appropriate and in conformance with the PUC’s order allowing the continuation of its existing DSM programs pending the resolution of the EE DSM Docket. The issues of whether DSM incentive mechanisms are appropriate to encourage the implementation of DSM programs, the appropriate mechanism(s) for such DSM incentives, and whether HECO’s proposed DSM utility incentive is reasonable are included in the Statement of Issues in the Prehearing Order in the EE DSM Docket.

On April 26, 2006, the PUC issued an Interim Decision and Order (D&O) approving HECO’s request to modify its existing DSM programs and implement its proposed interim DSM program. However, the PUC also ordered HECO’s recovery of lost margins and shareholder incentives for its DSM programs be discontinued within 30 days of the Interim D&O, until further order by the PUC. HECO is evaluating the impact of the Interim D&O. Lost margins and shareholder incentives are estimated and recorded in the year earned, and collected from ratepayers in the current year (lost margins) or the following year (shareholder incentives). Revenues that HECO expected to accrue for lost margins and shareholder incentives from May 26, 2006 through the end of 2006 had been estimated at $2.1 million, which amounts to $1.2 million in after-tax net income.

In October 2001, HELCO and MECO reached similar agreements with the Consumer Advocate regarding the continuation of their DSM programs and filed requests to continue their four existing DSM programs. In November 2001, the PUC issued orders (one of which was later amended) that, subject to certain reporting requirements and other conditions, approved the agreements regarding the temporary continuation of HELCO’s and MECO’s DSM programs until one year after the PUC makes a revenue requirements determination in HECO’s next rate case. Under the orders, however, HELCO and MECO are allowed to recover only lost margins and shareholder incentives accrued through the date that interim rates are established in HECO’s next rate case, but may request to extend the time of such accrual and recovery for up to one additional year. The temporary continuation of HECO’s existing DSM programs, as a result of the bifurcation order in HECO’s rate case, had the effect of postponing the deadline for the recovery of HELCO and MECO’s lost margins and shareholder incentives until resolution of the EE DSM Docket. Based on the Interim D&O, HELCO and MECO plan to file a request for a one-year extension for the recovery of HELCO and MECO’s lost margins and shareholder incentives or until final resolution of the EE DSM Docket. Revenues that HELCO and MECO expected to accrue for lost margins and shareholder incentives from May 26, 2006 through the end of 2006 had been estimated at $1.1 million and $2.6 million, respectively, which amounts to $0.6 million and $1.5 million in after-tax net income, respectively.

Integrated resource planning, requirements for additional generating capacity and adequacy of supply. The PUC issued an order in 1992 requiring the energy utilities in Hawaii to develop integrated resource plans (IRPs). The goal of integrated resource planning is the identification of demand- and supply-side resources and the integration of these resources for meeting near- and long-term consumer energy needs in an efficient and reliable manner at the lowest reasonable cost. The utilities’ proposed IRPs are planning strategies, rather than fixed courses of action, and the resources ultimately added to their systems may differ from those included in their 20-year plans. Under the PUC’s IRP framework, the utilities are required to submit annual evaluations of their plans (including a revised five-year program implementation schedule) and to submit new plans on a three-year cycle, subject to changes approved by the PUC. Prior to proceeding with the DSM programs, separate PUC approval proceedings must be completed.

The utilities are entitled to recover all appropriate and reasonable integrated resource planning and implementation costs, including the costs of DSM programs, either through a surcharge or through their base rates. Under procedural schedules for the IRP cost proceedings, the utilities can begin recovering their incremental IRP costs in the month following the filing of their actual costs incurred for the year, subject to refund with interest pending the PUC’s final D&O approving recovery of the costs.

The Consumer Advocate has objected to the recovery of $3.2 million (before interest) of the $11.8 million of incremental IRP costs incurred by the utilities during the 1995-2004 period, and the PUC’s decision is pending on this matter. As of March 31, 2006, the amount of revenues, including interest and revenue taxes, that the electric utilities recorded for IRP cost recoveries, subject to refund with interest, amounted to $18 million.

HECO’s IRP. In October 2005, HECO filed its third IRP (IRP-3), which proposes multiple solutions to meet Oahu’s future energy needs, including renewable energy resources, energy efficiency, conservation, technology (such as CHP and DG) and central station generation.

In June 2005, HECO filed with the PUC an application for approval of funds to build a new nominal 100 MW simple cycle combustion turbine generating unit at Campbell Industrial Park and an additional 138 kilovolt transmission line to transmit power from the new unit and existing generating units at Campbell Industrial Park to the Oahu electric grid. Plans are for the combustion turbine to be run primarily as a “peaking” unit beginning in 2009, and to burn naphtha or diesel, but will have the ability to convert to using biofuels, such as ethanol, when commercially

available. On December 15, 2005, HECO signed a contract with Siemens for the right to purchase up to two combustion turbine units. The contract allows the Company to terminate the contract at a specified payment amount if necessary combustion turbine (CT) project approvals are not obtained. In April 2006, HECO issued Solicitation of Interest letters to prospective suppliers of ethanol, asking them to indicate their ability to provide ethanol to specifications such as chemical composition and heat generating capacity, for use in a blend of ethanol and naphtha in the new generating unit. After reviewing responses, HECO, in consultation with the PUC and the Consumer Advocate, may issue a more detailed request for proposals or enter into direct negotiations with potential providers. The PUC would need to approve any ethanol fuel contract.

Preliminary costs for the new generating unit and transmission line, as well as related substation improvements, are estimated at $137 million. As of March 31, 2006 accumulated project costs for planning, engineering, permitting and AFUDC amounted to $2.9 million. HECO prepared a Draft Environmental Impact Statement and notice of its availability was published on February 8, 2006. The public comment period ended March 28, 2006. HECO is now preparing a Final Environmental Impact Statement for the proposed project that will include responses to the comments received.

In a related application filed with the PUC in June 2005, HECO requested approval for an approximately $11.5 million package of community benefit measures to mitigate the impact of the new generating unit on communities near the proposed generating unit site. These measures include a base electric rate discount for those who live near the proposed generation site, additional air quality monitoring stations, a fish monitoring program and the use of recycled instead of potable water in Kahe power plant’s operations.

The PUC granted an environmental group’s motion to intervene and a neighboring business entity’s motion to participate in the generating unit and transmission line application. The procedural schedule for the proceeding include hearings in December 2006. For the community benefits application, the only party is the Consumer Advocate, and hearings are scheduled for November 2006.

IRP-3 also includes possible plans to build a 180 MW coal unit in 2022. In addition, all existing generating units are currently planned to be operated (future environmental considerations permitting) beyond the 20-year IRP planning period (2006-2025).

MECO’s IRP. MECO filed its second IRP with the PUC in May 2000, and updated it in 2004 and 2005. On the supply side, MECO’s second IRP focused on the planning for the installation of approximately 150 MW of additional generation through the year 2020 on the island of Maui, including 38 MW of generation at its Maalaea power plant site in increments from 2000-2005, 100 MW at its new Waena site in increments from 2007-2018, beginning with a 20 MW combustion turbine in 2007 (currently planned to be added in 2011), and 10 MW from the acquisition of a wind resource in 2003 (currently, MECO expects to begin purchasing 30 MW of wind energy in 2006). Approximately 4 MW of additional generation through the year 2020 is planned for each of the islands of Lanai and Molokai. MECO completed the installation of a 20 MW increment (the second) at Maalaea in September 2000, and the final increment of 18 MW, which was originally expected to be installed in 2005, is currently expected to be installed in the third quarter of 2006.

MECO’s third IRP is scheduled to be filed with the PUC in October 2006.

HELCO’s IRP. In September 1998, HELCO filed its second IRP with the PUC, and updated it in 1999 and 2004. On the supply side, HELCO’s second IRP focused on the planning for generating unit additions after near-term additions. The near-term additions included installing two 20 MW CTs at its Keahole power plant site (which were put into limited commercial operation in May and June 2004) and a PPA with Hamakua Energy Partners, L.P. (HEP) for a 60 MW (net) facility (which was completed in December 2000). HELCO has deferred the retirements of some of its older generating units. HELCO’s current plans are to install an 18 MW heat recovery steam generator (ST-7) in 2009 or earlier. After the installation of ST-7, the target date in HELCO’s updated second IRP for the next firm capacity addition is the 2017 timeframe.

HELCO’s third IRP is scheduled to be filed with the PUC by December 31, 2006.

Adequacy of supply.

HECO. As a result of load growth and other factors, HECO’s 2005 Adequacy of Supply letter filed in March 2005 concluded that generation reserve margins, although substantial, were lower than is considered desirable on Oahu under the circumstances, and that there was an increased risk to generation reliability. Also, the letter stated that the risk of having generation-related customer outages would be higher if the peak reduction impacts of planned energy efficiency DSM programs, load management programs or CHP installations fall short of achieving their forecasted benefits. This situation is expected to continue if the peak demand continues to grow as forecasted, at least until 2009, which is the earliest that HECO expects to be able to install its planned combustion turbine. The letter also indicated that HECO was working on plans to implement a number of potential interim mitigation measures, such as installing portable, leased, distributed 1.6 MW generating units at substations or other sites (nine units totaling 14.8 MW were installed in the fourth quarter of 2005) and initiating a customer demand response program to supplement its load management programs (for which HECO plans to request approval in the first half of 2006). HECO did not experience actual generation shortfalls causing customer load shedding in 2005, in part because peak loads were lower than forecast in the second half of 2005.

HECO’s 2006 Adequacy of Supply letter filed in March 2006 indicates that HECO’s latest analysis estimates the reserve capacity shortfall to be between 170 MW and 200 MW in the 2006 to 2009 period, which is significantly larger than the 50 to 70 MW shortfall projected in the 2005 Adequacy of Supply letter. The increase in projected reserve capacity shortfall is largely due to the lower projected availability of existing generating units, and a reduction in the projected impacts from planned peak reduction measures. Generating units may be entirely or partially unavailable to serve load during scheduled overhaul periods and other planned maintenance outages, or when they “trip” or are taken out of operation or their output is “de-rated” due to equipment failure or other causes. While the availability rates for generating units on Oahu remain better than those of comparable units on the U.S. mainland, the availability rates have declined in 2004 and 2005. Based on this experience, the manner in which the units must be operated when there is a reserve capacity shortfall, and the increasing ages of the units, HECO expects this situation to continue in the near-term and is forecasting lower availability rates than were used in the 2005 analyses.

To mitigate the projected reserve capacity shortfalls and to increase generating unit availability going forward, HECO is continuing to plan and implement mitigation measures, such as installing additional distributed generators at substations or other sites, seeking approval for additional load management and other demand reduction measures, and pursuing efforts to improve the availability of generating units. HECO will operate at lower than desired reliability levels and take steps to mitigate the reserve capacity shortfall situation until the next generating unit is installed. Until sufficient generating capacity can be added to the system, HECO will experience a higher risk of generation related customer outages. Given the magnitude of the projected reserve capacity shortfall, HECO also will evaluate the need to file an application with the PUC for approval to add more firm capacity (over and above the PUC application filed in June 2005 for a 100 MW simple-cycle combustion turbine at Campbell Industrial Park). HECO did not experience actual generation shortfalls that caused shedding of firm customers in the first quarter of 2006. However, HECO’s system peak loads generally occur in the fourth quarter of the year, and the possibility remains for generation shortfall events in subsequent periods.

HELCO. HELCO’s 2006 Adequacy of Supply letter filed in February 2006 indicated that HELCO’s generation capacity for the next three years, 2006 through 2008, is sufficiently large to meet all reasonably expected demands for service and provide reasonable reserves for emergencies.

MECO. MECO’s 2006 Adequacy of Supply letter filed in March 2006 indicated that MECO’s Maui island system should have sufficient installed capacity to meet the forecasted loads. However, in December 2005, MECO’s Maalaea Unit 13, a 12.34 MW diesel generator suffered an equipment failure and the unit is not expected to be available for service until approximately June 2007. Until Maalaea Unit 13 returns to service, the Maui island system may not have sufficient capacity in the event of an unexpected outage of the largest unit. MECO will implement appropriate mitigation measures to overcome insufficient reserve capacity situations. On April 3, 2006,

MECO experienced lower than normal generation capacity due to the temporary loss of several generating units, and issued a request for the public to voluntarily conserve electricity.

Collective bargaining agreements

See “Collective bargaining agreements” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.”

Legislation and regulation

Congress and the State of Hawaii Legislature periodically consider legislation that could have positive or negative effects on the utilities and their customers. For information about legislation and regulation impacting HECO and its subsidiaries, see pages 70 to 72 of HEI’s 2005 Form 10-K. Following are legislation and regulation updates.

2006 Hawaii State Legislature energy measures. The 2006 Hawaii State Legislature passed energy measures, which if approved or allowed to take effect by the Governor will become State law, including the following:

Renewable Portfolio Standards (RPS). The State RPS law was amended to provide that at least 50% of the RPS targets must be met by electrical energy generated using renewable energy sources such as wind or solar versus from the electrical energy savings from renewable energy displacement technologies (such as solar water heating) or from energy efficiency and conservation programs. The amendment also added provisions for penalties to be established by the PUC if the RPS requirements are not met and criteria for waiver of the penalties by the PUC, if the requirements cannot be met due to circumstances beyond the company’s control. And the amendment extends the date to December 31, 2007 for the PUC to develop and implement a utility rate making structure to provide incentives to encourage electric utilities to use cost effective renewable energy resources.

DSM Programs. The PUC was given the authority, if it deems appropriate, to redirect all or a portion of the funds collected through the current utility DSM surcharge into a Public Benefits Fund, for the purpose of supporting customer DSM programs approved by the PUC. If the fund is established, the PUC is required to appoint a fund administrator (other than an electric utility or utility affiliate), to operate and manage the programs established under the fund.

Non-fossil Fuel Purchased Power Contracts. The PUC will be required to delink the price paid for non-fossil-fuel-generated electricity under future power purchase contracts from the price of fossil fuel, in order to allow utility customers to receive the potential cost savings from non-fossil fuel generation.

Public Utility Holding Company Act of 1935 (1935 Act) and Public Utility Holding Company Act of 2005 (2005 Act). The repeal of the 1935 Act, effective February 8, 2006, eliminated significant federal restrictions on the scope, structure and ownership of electric utilities. Some believe that the repeal will result in increased institutional ownership of and private equity and hedge fund investments in public utilities, increased consolidation in the industry, more Federal Energy Regulatory Commission (FERC) oversight, and additional diversification by electric utilities. The increased oversight by FERC results in part from the adoption of the 2005 Act, which provides for FERC access to the books and records of utility holding companies and, absent exemptions or waivers, imposes certain record retention and accounting requirements on public utility holding companies. HEI and HECO filed a notification claiming a waiver of such requirements as single-state public utility holding companies. FERC issued a notice of this petition for waiver on March 1, 2006, directing any protests or requests for intervention to be filed by March 14, 2006. Review of the FERC online library for this docket discloses no protest or request. Regulation and oversight of HECO and its subsidiaries by the PUC remain unchanged.

Electronic shock absorber (ESA). HECO received a U.S. patent in February 2005 for an ESA that addresses power fluctuations from wind resources. An ESA demonstration system has been installed and is currently being tested at HELCO’s Lalamilo wind farm. HECO has an intellectual property license agreement with the party constructing the ESA demonstration system. That party has the right to seek international patents for the design. Management cannot predict the amount of royalties HECO may receive from the sale of ESAs in the future.

Net energy metering. Hawaii has a net energy metering law, which requires that electric utilities offer net energy metering to eligible customer generators (i.e., a customer generator may be a net user or supplier of energy and will make payment to or receive credit from the electric utility accordingly). The 2004 Legislature amended the net energy metering law by expanding the definition of “eligible customer generator” to include government entities, increasing the maximum size of eligible net metered systems from 10 kilowatts (kw) to 50 kw, and limiting exemptions from additional requirements for systems meeting safety and performance standards to systems of 10 kw or less. The 2005 Legislature passed a law granting the PUC the authority to increase the maximum allowable capacity of eligible customer generators to an amount greater than 50 kw by rule or order. These amendments could have a negative effect on electric utility sales. However, based on experience under the 10 kw limit and assessment of market opportunity for 50 kw applications, management does not expect any such effect to be material. The PUC opened an investigative proceeding on net energy metering in April 2006.

Broadband over Power Line (BPL) technology

To evaluate the technical feasibility of the “Broadband over Power Line” (BPL) technology and its applications, HECO completed a small-scale trial of the BPL technology in 2005. Based on the favorable results of the trial, HECO has proceeded with a pilot in an expanded residential/commercial area in Honolulu, which is expected to run through at least the fourth quarter of 2006. The emphasis of the entire effort is primarily focused on automatic meter reading, which is aimed at enabling time of use rates for residential and commercial customers. Other BPL-enabled utility applications being evaluated include distribution system line monitoring, residential direct load control and monitoring of distribution substation equipment. HECO is also evaluating broadband information services that might potentially be provided by other service providers.

In October 2004, the Federal Communications Commission (FCC) released a Report and Order that amended and adopted new rules for Access Broadband over Power Line systems (Access BPL) and stated that an FCC goal in developing the rules for Access BPL “are therefore to provide a framework that will both facilitate the rapid introduction and development of BPL systems and protect licensed radio services from harmful interference.” Currently, there are no PUC regulations for electric utility applications of BPL systems.

Commitments and contingencies

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

Recent accounting pronouncements and interpretations

See Note 7 of HECO’s “Notes to Consolidated Financial Statements.”

FINANCIAL CONDITION

Liquidity and capital resources

HECO believes that its ability, and that of its subsidiaries, to generate cash, both internally from operations and externally from issuances of equity and debt securities, commercial paper, lines of credit and bank borrowings, is adequate to maintain sufficient liquidity to fund their 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:


(in millions)	March 31, 2006				December 31, 2005
Short-term borrowings	$	145	7	%	$	136	7	%
Long-term debt		766	38			766	38
Preferred stock		34	2			34	2
Common stock equity		1,047	53			1,039	53

	$	1,992	100	%	$	1,975	100	%

As of May 1, 2006, the Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HECO securities were as follows:


	S&P	Moody’s

Commercial paper	A-2	P-2
Revenue bonds (senior unsecured, insured)	AAA	Aaa
HECO-obligated preferred securities of trust subsidiaries	BBB-	Baa2
Cumulative preferred stock (selected series)	Not rated	Baa3

The rating agencies use a combination of qualitative measures (i.e., assessment of business risk that incorporates an analysis of the qualitative factors such as management, competitive positioning, operations, markets and regulation) as well as quantitative measures (e.g., cash flow, debt, interest coverage and liquidity ratios) in determining the ratings of HECO securities. In April 2005, S&P affirmed its corporate credit ratings of HECO, but revised its outlook from stable to negative, citing HECO’s need for a rate increase, rising operating expenses and yet to be recovered investments. S&P’s ratings outlook “assesses the potential direction of a long-term credit rating over the intermediate term (typically six months to two years).” In response to the PUC’s interim rate decision for HECO, S&P stated “a final order that closely mirrors the interim ruling appears to be sufficient to lift key financial metrics to levels that are marginally suitable for Standard & Poor’s guideposts for the ‘BBB’ rating category.” However, S&P will reconsider its negative outlook when the PUC issues its final order. In addition, S&P ranks business profiles from “1” (strong) to “10” (weak). In May 2005, S&P revised HECO’s business profile from “6” to “5”. Moody’s maintains a stable outlook for HECO.

HECO utilizes short-term debt, principally commercial paper, to support normal operations and for other temporary requirements. HECO also periodically borrows short-term from HEI for itself and on behalf of HELCO and MECO, and HECO may borrow from or loan to HELCO and MECO short-term. At March 31, 2006, HECO had $0.8 million of short-term borrowings from MECO and HELCO had $49.6 million of short-term borrowings from HECO. HECO had an average outstanding balance of commercial paper for the first three months of 2006 of $139 million and had $145 million of commercial paper outstanding as of March 31, 2006. Management believes that if HECO’s commercial paper ratings were to be downgraded, it may be more difficult for HECO to sell commercial paper under current market conditions.

BBB+/Baa1 to BBB/Baa2 by S&P and Moody’s, respectively) would result in a commitment fee increase of 2 basis points and an interest rate increase of 10 basis points on any drawn amounts. On the other hand, a ratings upgrade (e.g., from BBB+/Baa1 to A-/A3) would result in a commitment fee decrease of 1 basis point and an interest rate decrease of 10 basis points on any drawn amounts. The agreement does not contain clauses that would affect access to the lines by reason of a ratings downgrade, nor does it have broad “material adverse change” clauses. However, the agreement does contain customary conditions that must be met in order to draw on it, including compliance with 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 48% for HELCO and 43% for MECO as of March 31, 2006)). In addition to customary defaults, HECO’s failure to maintain its financial ratios, as defined in its agreement, or meet other requirements will result in an event of default. For example, under its agreement, it is an event of default if HECO fails to maintain a “Consolidated Capitalization Ratio” (equity) of at least 35% (Ratio of 53% as of March 31, 2006), if HECO fails to remain a wholly-owned subsidiary of HEI or if any event or condition occurs that results in any “Material Indebtedness” of HECO or any of its significant subsidiaries being subject to acceleration prior to its scheduled maturity.

HECO’s $175 million credit facility will be maintained to support the issuance of commercial paper, but also may be drawn for capital expenditures and general corporate purposes. This facility replaced HECO’s six bilateral bank lines of credit totaling $175 million, which were terminated concurrently with the effectiveness of the new syndicated facility. HECO expects to file with the PUC in the second quarter of 2006 an application seeking approval to extend the termination date of its credit agreement from March 29, 2007, to March 31, 2011. As of May 1, 2006, the $175 million of credit facilities were undrawn.

Operating activities provided $49 million in net cash during the first three months of 2006. Investing activities during the same period used net cash of $36 million primarily for capital expenditures, net of contributions in aid of construction. Financing activities for the same period used net cash of $11 million, primarily due to the payment of $14 million in common and preferred dividends, partly offset by a $9 million net increase in short term borrowings.

In May 2005, up to $160 million of Special Purpose Revenue Bonds (SPRBs) ($100 million for HECO, $40 million for HELCO and $20 million for MECO) were authorized by the Hawaii legislature for issuance, with PUC approval of the projects to be financed, through June 30, 2010 to finance the electric utilities’ capital improvement projects.

In January 2005, the Department of Budget and Finance of the State of Hawaii issued, at par, Refunding Series 2005A SPRBs in the aggregate principal amount of $47 million (with a maturity of January 1, 2025 and a fixed coupon interest rate of 4.80%) and loaned the proceeds from the sale to HECO, HELCO and MECO. Proceeds from the sale, along with additional funds, were applied in February 2005 to redeem at a 1% premium a like principal amount of SPRBs bearing a higher interest coupon (HECO’s, HELCO’s, and MECO’s aggregate $47 million of 6.60% Series 1995A SPRBs with an original stated maturity of January 1, 2025).

In December 2005, an application was filed with the PUC requesting approval to issue up to a total of $165 million in taxable unsecured notes for HECO, MECO and HELCO (up to $100 million for HECO, up to $50 million for HELCO and up to $15 million for MECO). On January 20, 2006, a Registration Statement on Form S-3 was filed with the SEC covering $100 million, $50 million and $15 million aggregate principal amount, respectively, for HECO, HELCO and MECO of their respective taxable unsecured notes due 2036. It is anticipated that the proceeds from the sale of the notes will be used for capital expenditures and/or to repay short-term borrowings (including borrowings from affiliates) incurred for capital expenditures or to refinance short-term borrowings used for capital expenditures. The HELCO and MECO notes will be fully and unconditionally guaranteed by HECO.

BANK

RESULTS OF OPERATIONS


	Three months ended March 31,
(in thousands)	2006		2005		% change		Primary reason(s) for significant change
Revenues	$	100,004	$	97,224	3		Higher interest income (resulting from higher average balances and yields on loans, partly offset by lower average balances and yields on investment and mortgage-related securities) and higher noninterest income
Operating income		27,015		28,953	(7	)	Lower net interest income and reversal in first quarter 2005 of allowance for loan losses, partly offset by higher noninterest income and lower noninterest expense
Net income		16,827		17,761	(5	)	Lower operating income

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

Net interest margin

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. If the current interest rate environment persists, the potential for compression of ASB’s net interest income will continue to be a concern. 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. As of March 31, 2006 and December 31, 2005, ASB’s loan portfolio mix, net, consisted of 74% residential loans, 11% commercial loans, 8% commercial real estate loans and 7% consumer loans. ASB’s mortgage-related securities portfolio consists primarily of shorter-duration assets and is affected by market interest rates and demand.

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. Advances from the FHLB of Seattle and securities sold under agreements to repurchase continue to be significant sources of funds, but the amount of advances has trended downward over the last few years. As of March 31, 2006 and December 31, 2005, ASB’s costing liabilities consisted of 74% deposits and 26% other borrowings.

Other factors primarily affecting ASB’s operating results include fee income, provision (or reversal of allowance) for loan losses, gains or losses on sales of securities available-for-sale and expenses from operations.

Although higher long-term interest rates could reduce the market value of available-for-sale investments and mortgage-related securities and reduce stockholder’s equity through a balance sheet charge to 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 an “other-than-temporary” impairment in the value of the securities. As of March 31, 2006 and December 31, 2005, the unrealized losses, net of tax benefits, on available-for-sale investments and mortgage-related securities (including securities pledged for repurchase agreements) in AOCI was $50 million and $37 million, respectively, reflecting the impact of higher interest rates. See “Quantitative and qualitative disclosures about market risk.”

The following table sets forth average balances, interest and dividend income, interest expense and weighted-average yields earned and rates paid, for certain categories of earning assets and costing liabilities for the three months ended March 31, 2006 and 2005.


	Three months ended March 31
(dollars in thousands)	2006		2005		Change
Loans receivable
Average balances ¹	$	3,585,205	$	3,278,734	$	306,471
Interest income ²		55,153		48,513		6,640
Weighted-average yield (%)		6.17		5.92		0.25

Investments and mortgage-related securities
Average balances	$	2,606,480	$	2,905,074	$	(298,594	)
Interest income		29,173		34,073		(4,900	)
Weighted-average yield (%)		4.48		4.69		(0.21	)

Other investments ³
Average balances	$	180,697	$	162,795	$	17,902
Interest and dividend income		904		790		114
Weighted-average yield (%)		2.00		1.95		0.05

Total earning assets
Average balances	$	6,372,382	$	6,346,603	$	25,779
Interest and dividend income		85,230		83,376		1,854
Weighted-average yield (%)		5.36		5.26		0.10

Deposit liabilities
Average balances	$	4,550,700	$	4,320,599	$	230,101
Interest expense		15,393		12,017		3,376
Weighted-average rate (%)		1.37		1.13		0.24

Other borrowings
Average balances	$	1,614,099	$	1,786,314	$	(172,215	)
Interest expense		17,162		17,748		(586	)
Weighted-average rate (%)		4.30		4.01		0.29

Total costing liabilities
Average balances	$	6,164,799	$	6,106,913	$	57,886
Interest expense		32,555		29,765		2,790
Weighted-average rate (%)		2.14		1.97		0.17

Net average balance	$	207,583	$	239,690	$	(32,107	)
Net interest income		52,675		53,611		(936	)
Interest rate spread (%)		3.22		3.29		(0.07	)
Net interest margin (%) ⁴		3.29		3.36		(0.07	)

(1)	Includes nonaccrual loans.

(2)	Includes interest accrued prior to suspension of interest accrual on nonaccrual loans, together with loan fees of $1.4 million and $1.6 million for three months ended March 31, 2006 and 2005, respectively.

(3)

Includes stock in the FHLB of Seattle ($98 million and $97 million as of March 31, 2006 and 2005, respectively). For the three months ended March 31, 2006, no stock dividends were received compared to $0.4 million for the three months ended March 31, 2005. See “FHLB of Seattle business and capital plan” below.

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

Results – three months ended March 31, 2006

Net interest income before reversal of allowance for loan losses for three months ended March 31, 2006 decreased by $0.9 million, or 1.7%, when compared to the same period in 2005. ASB continued to grow its loans and deposits, however, the bank experienced some margin compression. Net interest margin decreased from 3.36% in the first quarter of 2005 to 3.29% in the first quarter of 2006 as higher balances and yields on loans were more than offset by lower balances and yields on investment and mortgage-related securities and higher funding costs. The increase in the average loan portfolio balance was partly due to the continued strength in the Hawaii economy and real estate market. The decrease in the average investment and mortgage-related securities portfolios was due to the reinvestment of excess liquidity into loans. The decrease in yields on the investment and mortgage-related securities portfolio was due to an upward adjustment to the amortized cost and yield of the mortgage-related securities in the first quarter of 2005 as a result of changing prepayment expectations. Average deposit balances grew by $230 million, enabling ASB to replace other borrowings and helping fund loan growth.

During the first quarter of 2006, the need to provide for loan losses as a result of additional loan growth was fully offset by the release of reserves on existing loans due to strong asset quality. This compares to a reversal of allowance for loan losses of $3.1 million ($1.9 million, net of tax) for the first quarter of 2005. As of March 31, 2006, ASB’s allowance for loan losses was 0.86% of average loans outstanding, compared to 0.90% at December 31, 2005 and 0.94% at March 31, 2005.


	Three months ended March 31
(in thousands)	2006		2005
Allowance for loan losses, January 1	$	30,595	$	33,857
Reversal of allowance for loan losses		—		(3,100	)
Net recoveries		66		19

Allowance for loan losses, March 31	$	30,661	$	30,776

First quarter of 2006 noninterest income increased by $0.9 million, or 6.7%, when compared to the first quarter of 2005, primarily due to higher fee income on debit cards and merchant services.

Noninterest expense for the three months ended March 31, 2006 decreased by $1.2 million, or 2.8%, when compared to the first quarter of 2005, primarily due to lower interest accruals on income taxes partially offset by higher compensation and employee benefits expense.

FHLB of Seattle business and capital plan

In December 2004, the FHLB of Seattle signed an agreement with its regulator, the Federal Housing Finance Board (Finance Board), to adopt a business and capital plan to strengthen its risk management, capital structure and governance. As of March 31, 2006, ASB had an investment in FHLB of Seattle stock of $98 million.

In April 2005, the FHLB of Seattle delivered a proposed three-year business plan and capital management plan to the Finance Board, and issued a press release stating that it anticipates minimal to no dividends in the next few years while it implements its new business model. No dividends were received by ASB from the FHLB of Seattle during the twelve months ended March 31, 2006. Subject to the impact of legislation being considered by Congress, member access to the FHLB of Seattle funding and liquidity is expected to continue unimpeded during implementation of the three-year plan.

FINANCIAL CONDITION

Liquidity and capital resources


(in millions)	March 31, 2006		December 31, 2005		% change
Total assets	$	6,865	$	6,835	—
Available-for-sale investment and mortgage-related securities		2,609		2,629	(1	)
Investment in FHLB of Seattle stock		98		98	—
Loans receivable, net		3,618		3,567	1
Deposit liabilities		4,610		4,557	1
Other borrowings		1,623		1,622	—

As of March 31, 2006, ASB was the third largest financial institution in Hawaii based on assets of $6.9 billion and deposits of $4.6 billion.

ASB’s S&P counterparty credit ratings are BBB-/A-3. In April 2006, S&P affirmed its counterparty credit ratings on ASB, but revised its outlook from stable to positive, acknowledging the promising potential of ASB’s community banking strategy, its still modest credit risk profile, and its solid capital base.

As of March 31, 2006, ASB’s unused FHLB borrowing capacity was approximately $1.5 billion. As of March 31, 2006, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.1 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 three months of 2006, net cash provided by ASB’s operating activities was $49 million. Net cash used during the same period by ASB’s investing activities was $63 million, primarily due to purchases of investment securities of $125 million, a net increase in loans receivable of $58 million, offset by repayments of mortgage-related securities of $122 million. Net cash provided by financing activities during this period was $44 million primarily due to net increases of $53 million in deposit liabilities and $36 million in securities sold under agreements to repurchase, offset by the repayment of $36 million of advances from the FHLB of Seattle and the payment of $10 million in common stock dividends.

As of March 31, 2006, ASB was well-capitalized (ratio requirements noted in parentheses) with a leverage ratio of 7.5% (5.0%), a Tier-1 risk-based capital ratio of 14.3% (6.0%) and a total risk-based capital ratio of 15.1% (10.0%).

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 80 to 86 of HEI’s 2005 Form 10-K.

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

MATERIAL ESTIMATES AND CRITICAL ACCOUNTING POLICIES

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 financial condition and results of operations, and currently require management’s most difficult, subjective or complex judgments. For information about these policies, see pages 86 to 89 of HEI’s 2005 Form 10-K.

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. In determining that HECO is not the primary beneficiary of Kalaeloa under the provisions of FIN 46R (see Note 2 of HECO’s “Notes to Consolidated Financial Statements”), management used estimates in computing Kalaeloa’s expected cash flows. Estimates used in the analysis, for example with respect to the variability of fuel usage and pricing and operational levels and costs, are particularly susceptible to change. Management used its best efforts to determine the expected cash flows based on historical experience, financial information provided by Kalaeloa and on various other assumptions that were believed to be reasonable under the circumstances, the results

of which formed the basis for the estimated cash flows. Actual results of Kalaeloa could differ significantly from those estimations.

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 financial condition and results of operations. For additional quantitative and qualitative information about the Company’s market risks, see pages 90 to 93 of HEI’s 2005 Form 10-K.

ASB’s interest-rate risk sensitivity measures as of March 31, 2006 and December 31, 2005 constitute “forward-looking statements” and were as follows:


	March 31, 2006						December 31, 2005
	Change in NII		NPV ratio		NPV ratio sensitivity *		Change in NII		NPV ratio		NPV ratio sensitivity *
Change in interest rates (basis points)	Gradual change		Instantaneous change				Gradual change		Instantaneous change
+300	(2.8	)%	7.71	%	(348	)	(2.7	)%	8.12	%	(332	)
+200	(1.9	)	8.94		(225	)	(1.8	)	9.34		(210	)
+100	(1.0	)	10.14		(105	)	(0.9	)	10.49		(95	)
Base	—		11.19		—		—		11.44		—
-100	1.6		11.88		69		1.5		11.91		47
-200	1.4		11.83		64		1.0		11.62		18
-300	(0.5	)	11.26		7		**		**		**

*	Change from base case in basis points.

**	Not performed as of December 31, 2005.

There was little change in the NII sensitivity profile as of March 31, 2006 when compared to the NII sensitivity profile as of December 31, 2005.

In the –300 basis point scenario, NII falls relative to the base case because expectations of faster prepayments and lower reinvestment rates causes the yield on assets to decline faster than the cost of liabilities.

ASB’s base NPV ratio as of March 31, 2006 was lower than on December 31, 2005, primarily as a result of changes in the level of interest rates. During the first quarter of 2006, the yield curve shifted up by approximately 50 basis points in an almost parallel fashion, causing the bank’s NPV ratio to decline.

ASB’s NPV ratio sensitivity measures as of March 31, 2006 were slightly higher when compared to the measures as of December 31, 2005, primarily a result of the higher level of interest rates.

The computation of the prospective effects of hypothetical interest rate changes on the NII sensitivity, NPV ratio, and NPV ratio sensitivity analyses 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.

Item 4. Controls and Procedures

HEI:

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Constance H. Lau, HEI Chief Executive Officer, and Eric K. Yeaman, HEI Chief Financial Officer, have evaluated the disclosure controls and procedures of HEI as of March 31, 2006. Based on their evaluations, as of March 31, 2006, 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.

Internal Control Over Financial Reporting

During the first quarter of 2006, there has been no change in internal control over financial reporting identified in connection with management’s evaluation of the effectiveness of the Company’s internal control over financial reporting as of March 31, 2006 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

HECO:

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

T. Michael May, HECO Chief Executive Officer, and Tayne S. Y. Sekimura, HECO Chief Financial Officer, have evaluated the disclosure controls and procedures of HECO as of March 31, 2006. Based on their evaluations, as of March 31, 2006, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective in ensuring that information required to be disclosed by HECO in reports HECO files or submits under the Securities Exchange Act of 1934:

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

(2) is accumulated and communicated to HECO management, including HECO’s principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Internal Control Over Financial Reporting

During the first quarter of 2006, there has been no change in internal control over financial reporting identified in connection with management’s evaluation of the effectiveness of HECO and its subsidiaries’ internal control over financial reporting as of March 31, 2006 that has materially affected, or is reasonably likely to materially affect, HECO and its subsidiaries’ internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

There were no significant developments in pending legal proceedings during the first quarter of 2006 except as set forth in HECO’s “Notes to Consolidated Financial Statements.” 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.

Item 1A. Risk Factors

For information about Risk Factors, see pages 36 to 44 of HEI’s 2005 Form 10-K, and “Forward-Looking Statements,” “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.

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

Purchases of HEI common shares were made 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
January 1 to 31, 2006	84,736	$	26.17	—	NA
February 1 to 28, 2006	66,178		26.40	—	NA
March 1 to 31, 2006	274,983		26.67	—	NA

	425,897	$	26.53	—	NA

NA	Not applicable.

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

The purchases were made to satisfy the requirements of the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP) and Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) for shares purchased for cash or by the reinvestment of dividends by participants under those plans and none of the purchases were made under publicly announced repurchase plans or programs. Average prices per share are calculated exclusive of any commissions payable to the brokers making the purchases for the DRIP and HEIRSP. Of the shares listed in column (a), 78,236 of the 84,736 shares, all of the 66,178 shares and 227,083 of the 274,983 shares were purchased for the DRIP and the remainder were purchased for the HEIRSP. All purchases were made through a broker on the open market.

Item 5. Other Information

A. Ratio of earnings to fixed charges.


	Three months ended March 31, 2006	Years ended December 31,
	Three months ended March 31, 2006	2005	2004	2003	2002	2001
HEI and Subsidiaries
Excluding interest on ASB deposits	2.33	2.31	2.32	2.11	2.03	1.82
Including interest on ASB deposits	1.95	1.98	2.00	1.84	1.72	1.52
HECO and Subsidiaries	3.38	3.23	3.49	3.36	3.71	3.51

See HEI Exhibit 12.1 and HECO Exhibit 12.2.

B. Public Utilities Commission of the State of Hawaii.

Carlito P. Caliboso (an attorney previously in private practice) continues to serve as Chairman of the PUC (term expiring June 30, 2010). Also serving as commissioners are Janet E. Kawelo (whose term expires June 30, 2006 and who previously served as the Deputy Director for the State Department of Land and Natural Resources) and Wayne H. Kimura (whose term expires June 30, 2008 and who previously served as State Comptroller with the State Department of Accounting and General Services).

In May 2006, John E. Cole was confirmed by the state senate for a six year term, effective July 1, 2006, following the expiration of Ms. Kawelo’s term. Mr. Cole, an attorney, has been serving as the Executive Director of the Division of Consumer Advocacy, and prior to holding that position he was a member of the Governor of the State of Hawaii’s Policy Team, which serves as advisor to the Governor on state-wide policy matters.

A new Executive Director of the Division of Consumer Advocacy has not yet been appointed.

Item 6. Exhibits

The exhibits designated by an asterisk (*) are filed herein. The exhibits not so designated are incorporated by reference to the indicated filing.



HEI Exhibit 3(i).1		HEI’s Restated Articles of Incorporation (Exhibit 4(b) to Registration Statement on Form S-3, Registration No. 33-7895)

HEI Exhibit 3(i).2		Articles of Amendment of HEI, amending HEI’s Restated Articles of Incorporation, Article Fourteenth, (Exhibit 4(b) to Registration Statement on Form S-3, Registration No. 33-40813)

HEI Exhibit 3(i).3		Statement of Issuance of Shares of Preferred or Special Classes in Series for HEI Series A Junior Participating Preferred Stock (Exhibit 3(i).3 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-8503)

HEI Exhibit 3(i).4 *		Articles of Amendment of HEI, amending HEI’s Restated Articles of Incorporation, Article Fourth

HEI Exhibit 3(i).5 *		Articles of Amendment of HEI, amending HEI’s Restated Articles of Incorporation, Article Sixth

HEI Exhibit 12.1 *		Hawaiian Electric Industries, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, three months ended March 31 2006 and 2005 and years ended December 31, 2005, 2004, 2003, 2002 and 2001

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 Eric K. Yeaman (HEI Chief Financial Officer)

HEI Exhibit 32.1 *		Written Statement of Constance H. Lau (HEI Chief Executive Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002

HEI Exhibit 32.2 *		Written Statement of Eric K. Yeaman (HEI Chief Financial Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002

HECO Exhibit 12.2 *		Hawaiian Electric Company, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, three months ended March 31 2006 and 2005 and years ended December 31, 2005, 2004, 2003, 2002 and 2001

HECO Exhibit 31.3 *		Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of T. Michael May (HECO Chief Executive Officer)

HECO Exhibit 31.4 *		Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Tayne S. Y. Sekimura (HECO Chief Financial Officer)

HECO Exhibit 32.3 *		Written Statement of T. Michael May (HECO Chief Executive Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002

HECO Exhibit 32.4 *		Written Statement of Tayne S. Y. Sekimura (HECO Chief Financial Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002

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/ T. Michael May
	Constance H. Lau		T. Michael May
	President and Chief Executive Officer		President and Chief Executive Officer
	(Principal Executive Officer of HEI)		(Principal Executive Officer of HECO)

By	/s/ Eric K. Yeaman	By	/s/ Tayne S. Y. Sekimura
	Eric K. Yeaman		Tayne S. Y. Sekimura
	Financial Vice President, Treasurer		Financial Vice President
	and Chief Financial Officer		(Principal Financial Officer of HECO)
	(Principal Financial Officer of HEI)

By	/s/ Curtis Y. Harada	By	/s/ Patsy H. Nanbu
	Curtis Y. Harada		Patsy H. Nanbu
	Controller		Controller
	(Chief Accounting Officer of HEI)		(Chief Accounting Officer of HECO)

Date: May 5, 2006		Date: May 5, 2006