HAWAIIAN ELECTRIC CO INC - Quarter Report: 2003 September (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 September 30, 2003

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

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

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. is an accelerated filer (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 issuer’s classes of common stock, as of the latest practicable date.

Class of Common Stock		Outstanding November 1, 2003
Hawaiian Electric Industries, Inc. (Without Par Value)		37,739,640 Shares
Hawaiian Electric Company, Inc. ($6²/3 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 September 30, 2003

INDEX

		Page No.
Glossary of terms		ii
Forward-looking statements and risk factors		v

PART I. FINANCIAL INFORMATION

Item 1.	Financial statements
	Hawaiian Electric Industries, Inc. and Subsidiaries

	Consolidated balance sheets (unaudited)–September 30, 2003 and December 31, 2002	1

	Consolidated statements of income (unaudited)–three and nine months ended September 30, 2003 and 2002	2

	Consolidated statements of changes in stockholders’ equity (unaudited)–nine months ended September 30, 2003 and 2002	3

	Consolidated statements of cash flows (unaudited)–nine months ended September 30, 2003 and 2002	4

	Notes to consolidated financial statements (unaudited)	5

	Hawaiian Electric Company, Inc. and Subsidiaries

	Consolidated balance sheets (unaudited)–September 30, 2003 and December 31, 2002	16

	Consolidated statements of income (unaudited)–three and nine months ended September 30, 2003 and 2002	17

	Consolidated statements of retained earnings (unaudited)–three and nine months ended September 30, 2003 and 2002	17

	Consolidated statements of cash flows (unaudited)–nine months ended September 30, 2003 and 2002	18

	Notes to consolidated financial statements (unaudited)	19

Item 2.	Management’s discussion and analysis of financial condition and results of operations	40

Item 3.	Quantitative and qualitative disclosures about market risk	63

Item 4.	Controls and procedures	64

PART II. OTHER INFORMATION

Item 1.	Legal proceedings	64

Item 5.	Other information	64

Item 6.	Exhibits and reports on Form 8-K	67

Signatures		69

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q–Quarter ended September 30, 2003

G LOSSARY OF TERMS

Terms		Definitions

AES Hawaii		AES Hawaii, Inc., formerly known as AES Barbers Point, Inc.

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 since March 15, 2001, Bishop Insurance Agency of Hawaii, Inc.), ASB Service Corporation, AdCommunications, Inc., American Savings Mortgage Co., Inc. (dissolved in July 2003) and ASB Realty Corporation

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

CDUP		Conservation District Use Permit

CEPALCO		Cagayan Electric Power & Light Co., Inc.

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 I, HECO Capital Trust II, Renewable Hawaii, Inc., HEI Diversified, Inc., American Savings Bank, F.S.B. and its subsidiaries, Pacific Energy Conservation Services, Inc., HEI District Cooling, Inc. (dissolved in October 2003), ProVision Technologies, Inc. (sold in July 2003), HEI Properties, Inc., HEI Leasing, Inc. (dissolved in October 2003), Hycap Management, Inc., Hawaiian Electric Industries Capital Trust I, Hawaiian Electric Industries Capital Trust II, Hawaiian Electric Industries Capital Trust III, HEI Preferred Funding, LP, The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.), HEI Power Corp. and its subsidiaries and Malama Pacific Corp. and its 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

DLNR		Department of Land and Natural Resources of the State of Hawaii

DOH		Department of Health of the State of Hawaii

DRIP		HEI Dividend Reinvestment and Stock Purchase Plan

GLOSSARY OF TERMS, continued

Terms		Definitions

EAB		Environmental Appeals Board

ECAC		Energy cost adjustment clause

EPA		Environmental Protection Agency–federal

FASB		Financial Accounting Standards Board

Federal		U.S. Government

FHLB		Federal Home Loan Bank

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 I, HECO Capital Trust II and Renewable Hawaii, Inc.

HEI		Hawaiian Electric Industries, Inc., direct parent company of Hawaiian Electric Company, Inc., HEI Diversified, Inc., Pacific Energy Conservation Services, Inc., HEI District Cooling, Inc. (dissolved in October 2003), ProVision Technologies, Inc. (sold in July 2003), HEI Properties, Inc., HEI Leasing, Inc. (dissolved in October 2003), Hycap Management, Inc., Hawaiian Electric Industries Capital Trust I, Hawaiian Electric Industries Capital Trust II, Hawaiian Electric Industries Capital Trust III, The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.), HEI Power Corp. and Malama Pacific Corp.

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 several subsidiaries. On October 23, 2001, the HEI Board of Directors adopted a formal plan to exit the international power business (engaged in by HEIPC and its subsidiaries).

HEIPC Group		HEI Power Corp. and its subsidiaries

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

HTB		Hawaiian Tug & Barge Corp. On November 10, 1999, HTB sold substantially all of its operating assets and the stock of Young Brothers, Limited, and changed its name to The Old Oahu Tug Service, Inc.

IPP		Independent power producer

iii

GLOSSARY OF TERMS, continued

Terms		Definitions

IRP		Integrated resource plan

kV		Kilovolt

KW		Kilowatt

KWH		Kilowatthour

LUC		Hawaii State Land Use Commission

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

MW		Megawatt

NII		Net interest income

NPV		Net portfolio value

OTS		Office of Thrift Supervision, Department of Treasury

PBR		Performance-based rate-making

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

SEC		Securities and Exchange Commission

SFAS		Statement of Financial Accounting Standards

SPRB		Special Purpose Revenue Bonds

TOOTS		The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp. (HTB)), a wholly owned subsidiary of Hawaiian Electric Industries, Inc. On November 10, 1999, HTB sold Young Brothers, Limited and substantially all of HTB’s operating assets and changed its name

YB		Young Brothers, Limited, which was sold on November 10, 1999, was formerly a wholly owned subsidiary of Hawaiian Tug & Barge Corp.

FORWARD-LOOKING STATEMENTS AND RISK FACTORS

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 (including future revenues, expenses, earnings or losses or growth rates), ongoing business strategies or prospects and possible future actions, which may be provided by management, 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 assumptions about HEI and its subsidiaries (including HECO and its subsidiaries), 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 Hawaii and continental U.S. housing markets and the military presence 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 and potential conflict or crisis with North Korea;

•

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;

•

capacity and supply constraints or difficulties;

•

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 independent power producers to deliver the firm capacity anticipated in their power purchase agreements;

•

the ability of the electric utilities to negotiate, periodically, favorable collective bargaining agreements;

•

new technological developments that could affect the operations and prospects of HEI’s subsidiaries (including HECO 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 and governmental fees and assessments); decisions by the Hawaii Public Utilities Commission (PUC) in rate cases and other proceedings and by other agencies and courts on land use, environmental and other permitting issues; required corrective actions (such as with respect to environmental conditions, capital adequacy and business practices);

•

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;

•

the effects of changes by securities rating agencies in the ratings of the securities of HEI and HECO;

•

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 American Savings Bank, F.S.B. (ASB);

•

the ultimate net proceeds from the disposition of assets and settlement of liabilities of discontinued or sold operations;

•

the final outcome of tax positions taken by HEI and its subsidiaries, including with respect to ASB’s real estate investment trust subsidiary and HEI’s discontinued operations;

•

the risks of suffering losses that are uninsured; and

•

other risks or uncertainties described elsewhere in this report and in other periodic reports previously and subsequently filed by HEI and/or HECO with the Securities and Exchange Commission (SEC).

Forward-looking statements speak only as of the date of the report, presentation or filing in which they are made. Except to the extent required by the federal securities laws, HEI 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)

(in thousands)	September 30, 2003		December 31, 2002
Assets
Cash and equivalents	$	199,601	$	244,525
Federal funds sold		34,677		—
Accounts receivable and unbilled revenues, net		174,608		176,327
Available-for-sale investment and mortgage-related securities		1,800,552		1,960,288
Available-for-sale mortgage-related securities pledged for repurchase agreements		937,337		784,362
Held-to-maturity investment securities		93,447		89,545
Loans receivable, net		3,142,148		2,993,989
Property, plant and equipment, net of accumulated depreciation of $1,521,098 and $1,437,366		2,083,812		2,079,325
Regulatory assets		105,565		105,568
Other		360,689		345,002
Goodwill and other intangibles		95,271		97,572

	$	9,027,707	$	8,876,503

Liabilities and stockholders’ equity
Liabilities
Accounts payable	$	157,420	$	134,416
Deposit liabilities		3,952,662		3,800,772
Securities sold under agreements to repurchase		787,585		667,247
Advances from Federal Home Loan Bank		1,037,052		1,176,252
Long-term debt, net		1,063,790		1,106,270
Deferred income taxes		219,556		235,431
Contributions in aid of construction		221,242		218,094
Other		286,594		257,315

		7,725,901		7,595,797

Minority interests
HEI- and HECO-obligated preferred securities of trust subsidiaries		200,000		200,000
Preferred stock of subsidiaries–not subject to mandatory redemption		34,406		34,406

		234,406		234,406

Stockholders’ equity
Preferred stock, no par value, authorized 10,000 shares; issued: none		—		—
Common stock, no par value, authorized 100,000 shares; issued and outstanding: 37,690 shares and 36,809 shares		876,804		839,503
Retained earnings		183,735		176,118
Accumulated other comprehensive income		6,861		30,679

		1,067,400		1,046,300

	$	9,027,707	$	8,876,503

See accompanying “Notes to consolidated financial statements.”

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 September 30,						Nine months ended September 30,
	2003			2002			2003			2002
Revenues
Electric utility	$	359,250		$	333,636		$	1,042,691		$	919,643
Bank		93,770			99,722			281,575			300,633
Other		683			(1,798	)		2,829			(2,278	)

		453,703			431,560			1,327,095			1,217,998

Expenses
Electric utility		312,614			280,047			912,495			769,497
Bank		68,654			75,156			211,672			229,527
Other		4,200			4,619			14,152			12,006

		385,468			359,822			1,138,319			1,011,030

Operating income (loss)
Electric utility		46,636			53,589			130,196			150,146
Bank		25,116			24,566			69,903			71,106
Other		(3,517	)		(6,417	)		(11,323	)		(14,284	)

		68,235			71,738			188,776			206,968

Interest expense–other than bank		(17,315	)		(17,751	)		(53,174	)		(54,618	)
Allowance for borrowed funds used during construction		496			549			1,385			1,392
Preferred stock dividends of subsidiaries		(501	)		(501	)		(1,504	)		(1,504	)
Preferred securities distributions of trust subsidiaries		(4,008	)		(4,008	)		(12,026	)		(12,026	)
Allowance for equity funds used during construction		1,098			1,162			3,075			2,977

Income from continuing operations before income taxes		48,005			51,189			126,532			143,189
Income taxes		17,483			17,677			45,923			51,347

Income from continuing operations		30,522			33,512			80,609			91,842
Discontinued operations-loss from operations net of income tax benefits		—			—			(3,870	)		—

Net income	$	30,522		$	33,512		$	76,739		$	91,842

Basic earnings (loss) per common share
Continuing operations	$	0.81		$	0.92		$	2.16		$	2.54
Discontinued operations		—			—			(0.10	)		—

	$	0.81		$	0.92		$	2.06		$	2.54

Diluted earnings (loss) per common share
Continuing operations	$	0.81		$	0.91		$	2.15		$	2.53
Discontinued operations		—			—			(0.10	)		—

	$	0.81		$	0.91		$	2.05		$	2.53

Dividends per common share	$	0.62		$	0.62		$	1.86		$	1.86

Weighted-average number of common shares outstanding		37,516			36,435			37,205			36,150
Dilutive effect of stock options and dividend equivalents		160			192			159			200

Adjusted weighted-average shares		37,676			36,627			37,364			36,350

Ratio of earnings to fixed charges (SEC method)
Excluding interest on ASB deposits								2.01			2.08

Including interest on ASB deposits								1.76			1.75

See accompanying “Notes to consolidated financial statements.”

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated statements of changes in stockholders’ equity (unaudited)

	Common stock			Retained earnings			Accumulated other comprehensive income (loss)
(in thousands, except per share amounts)	Shares	Amount		Retained earnings						Total
Balance, December 31, 2002	36,809	$	839,503	$	176,118		$	30,679		$	1,046,300
Comprehensive income:
Net income	—		—		76,739			—			76,739
Net unrealized losses on securities:
Net unrealized losses arising during the period, net of tax benefits of $8,886	—		—		—			(21,708	)		(21,708	)
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $1,082	—		—		—			(2,110	)		(2,110	)

Comprehensive income (loss)	—		—		76,739			(23,818	)		52,921

Issuance of common stock, net	881		37,301		—			—			37,301
Common stock dividends ($1.86 per share)	—		—		(69,122	)		—			(69,122	)

Balance, September 30, 2003	37,690	$	876,804	$	183,735		$	6,861		$	1,067,400

Balance, December 31, 2001	35,600	$	787,374	$	147,837		$	(5,546	)	$	929,665
Comprehensive income:
Net income	—		—		91,842			—			91,842
Net unrealized gains on securities:
Net unrealized gains arising during the period, net of taxes of $13,048	—		—		—			38,555			38,555
Add: reclassification adjustment for net realized losses included in net income, net of tax benefits of $1,093	—		—		—			817			817
Minimum pension liability adjustment, net of tax benefits of $287	—		—		—			(468	)		(468	)

Comprehensive income	—		—		91,842			38,904			130,746

Issuance of common stock, net	972		43,055		—			—			43,055
Common stock dividends ($1.86 per share)	—		—		(67,218	)		—			(67,218	)

Balance, September 30, 2002	36,572	$	830,429	$	172,461		$	33,358		$	1,036,248

See accompanying “Notes to consolidated financial statements.”

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated statements of cash flows (unaudited)

Nine months ended September 30	2003			2002
(in thousands)
Cash flows from operating activities
Income from continuing operations	$	80,609		$	91,842
Adjustments to reconcile income from continuing operations to net cash provided by operating activities
Depreciation of property, plant and equipment		90,551			86,660
Other amortization		25,683			18,151
Provision for loan losses		2,775			8,000
Writedowns of income notes		—			3,657
Deferred income taxes		(4,609	)		33,072
Allowance for equity funds used during construction		(3,075	)		(2,977	)
Changes in assets and liabilities
Decrease (increase) in accounts receivable and unbilled revenues, net		1,719			(6,140	)
Increase in accounts payable		23,004			31,693
Increase (decrease) in taxes accrued		37,753			(43,423	)
Changes in other assets and liabilities		(27,732	)		(28,865	)

Net cash provided by operating activities		226,678			191,670

Cash flows from investing activities
Available-for-sale mortgage-related securities purchased		(1,899,634	)		(1,299,343	)
Principal repayments on available-for-sale mortgage-related securities		1,609,048			857,932
Proceeds from sale of mortgage-related securities		243,406			77,264
Loans receivable originated and purchased		(1,187,070	)		(789,453	)
Principal repayments on loans receivable		986,095			646,095
Proceeds from sale of loans		52,584			103,444
Proceeds from sale of real estate acquired in settlement of loans		4,073			9,464
Capital expenditures		(94,978	)		(82,229	)
Contributions in aid of construction		10,296			7,394
Other		(723	)		(353	)

Net cash used in investing activities		(276,903	)		(469,785	)

Cash flows from financing activities
Net increase in deposit liabilities		151,890			69,869
Net increase in short-term borrowings with original maturities of three months or less		—			29,829
Net increase in retail repurchase agreements		10,710			9,765
Proceeds from securities sold under agreements to repurchase		1,527,575			901,531
Repayments of securities sold under agreements to repurchase		(1,413,275	)		(976,837	)
Proceeds from advances from Federal Home Loan Bank		318,500			259,000
Principal payments on advances from Federal Home Loan Bank		(457,700	)		(108,000	)
Proceeds from issuance of long-term debt		167,360			11,691
Repayment of long-term debt		(210,000	)		(64,500	)
Preferred securities distributions of trust subsidiaries		(12,026	)		(12,026	)
Net proceeds from issuance of common stock		23,015			26,564
Common stock dividends		(56,172	)		(54,880	)
Other		(6,970	)		(9,601	)

Net cash provided by financing activities		42,907			82,405

Net cash used in discontinued operations		(2,929	)		(3,650	)

Net decrease in cash and equivalents and federal funds sold		(10,247	)		(199,360	)
Cash and equivalents and federal funds sold, beginning of period		244,525			450,827

Cash and equivalents and federal funds sold, end of period	$	234,278		$	251,467

See accompanying “Notes to consolidated financial statements.”

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 and with 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 HEI’s Annual Report on SEC Form 10-K for the year ended December 31, 2002 and the unaudited consolidated financial statements and the notes thereto in HEI’s Quarterly Reports on SEC Form 10-Q for the quarters ended March 31, 2003 and June 30, 2003.

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 September 30, 2003 and December 31, 2002, the results of its operations for the three and nine months ended September 30, 2003 and 2002, and its cash flows for the nine months ended September 30, 2003 and 2002. 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

Segment financial information was as follows:

(in thousands)	Electric Utility		Bank	Other		Total
Three months ended September 30, 2003
Revenues from external customers	$	359,250	93,770	683		$	453,703

Profit (loss)*	$	34,309	23,715	(10,019	)	$	48,005
Income taxes (benefit)		13,949	8,440	(4,906	)		17,483

Income (loss) from continuing operations	$	20,360	15,275	(5,113	)	$	30,522

Nine months ended September 30, 2003
Revenues from external customers	$	1,042,689	281,575	2,831		$	1,327,095
Intersegment revenues (eliminations)		2	—	(2	)		—

Revenues	$	1,042,691	281,575	2,829		$	1,327,095

Profit (loss)*	$	93,349	65,731	(32,548	)	$	126,532
Income taxes (benefit)		36,777	23,454	(14,308	)		45,923

Income (loss) from continuing operations	$	56,572	42,277	(18,240	)	$	80,609

Assets (at September 30, 2003, including net assets of discontinued operations)	$	2,468,194	6,455,776	103,737		$	9,027,707

Three months ended September 30, 2002
Revenues from external customers	$	333,635	99,722	(1,797	)	$	431,560
Intersegment revenues (eliminations)		1	—	(1	)		—

Revenues	$	333,636	99,722	(1,798	)	$	431,560

Profit (loss)*	$	41,829	23,171	(13,811	)	$	51,189
Income taxes (benefit)		16,219	8,519	(7,061	)		17,677

Income (loss) from continuing operations	$	25,610	14,652	(6,750	)	$	33,512

Nine months ended September 30, 2002
Revenues from external customers	$	919,639	300,633	(2,274	)	$	1,217,998
Intersegment revenues (eliminations)		4	—	(4	)		—

Revenues	$	919,643	300,633	(2,278	)	$	1,217,998

Profit (loss)*	$	114,015	66,917	(37,743	)	$	143,189
Income taxes (benefit)		44,196	24,102	(16,951	)		51,347

Income (loss) from continuing operations	$	69,819	42,815	(20,792	)	$	91,842

Assets (at September 30, 2002, including net assets of discontinued operations)	$	2,411,180	6,241,788	110,269		$	8,763,237

*	Income (loss) from continuing operations before income taxes.

Revenues attributed to foreign countries and long-lived assets located in foreign countries as of the dates and for the periods identified above were not material.

(3) Electric utility subsidiary

For HECO’s consolidated financial information, including its commitments and contingencies, see pages 16 through 39.

(4) Bank subsidiary

Selected financial information

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

Consolidated balance sheet data

(in thousands)	September 30, 2003		December 31, 2002
Assets
Cash and equivalents	$	149,952	$	214,704
Federal funds sold		34,677		—
Available-for-sale mortgage-related securities		1,788,477		1,952,317
Available-for-sale mortgage-related securities pledged for repurchase agreements		937,337		784,362
Held-to-maturity investment securities		93,447		89,545
Loans receivable, net		3,142,148		2,993,989
Other		214,467		196,117
Goodwill and other intangibles		95,271		97,572

	$	6,455,776	$	6,328,606

Liabilities and equity
Deposit liabilities–noninterest bearing	$	452,500	$	369,961
Deposit liabilities–interest bearing		3,500,162		3,430,811
Securities sold under agreements to repurchase		787,585		667,247
Advances from Federal Home Loan Bank		1,037,052		1,176,252
Other		137,535		137,888

		5,914,834		5,782,159
Minority interests and preferred stock of subsidiary		3,529		3,417
Preferred stock		75,000		75,000

Common stock		244,452		243,628
Retained earnings		214,763		192,692
Accumulated other comprehensive income		3,198		31,710

		462,413		468,030

	$	6,455,776	$	6,328,606

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

Consolidated statements of income (unaudited)

	Three months ended September 30,					Nine months ended September 30,
(in thousands)	2003		2002			2003		2002
Interest and dividend income
Interest and fees on loans	$	49,657	$	50,210		$	150,555	$	152,300
Interest on mortgage-related securities		24,876		35,503			80,176		103,634
Interest and dividends on investment securities		1,428		1,880			4,736		5,979

		75,961		87,593			235,467		261,913

Interest expense
Interest on deposit liabilities		13,099		17,833			41,182		57,331
Interest on Federal Home Loan Bank advances		11,449		14,905			37,067		43,327
Interest on securities sold under repurchase agreements		5,287		5,683			16,059		15,256

		29,835		38,421			94,308		115,914

Net interest income		46,126		49,172			141,159		145,999
Provision for loan losses		600		1,500			2,775		8,000

Net interest income after provision for loan losses		45,526		47,672			138,384		137,999

Other income
Fees from other financial services		6,015		5,416			17,964		15,381
Fee income on deposit liabilities		4,423		4,091			12,257		11,717
Fee income on other financial products		2,426		2,592			7,660		7,647
Fee income on loans serviced for others, net		1,952		(882	)		508		(369	)
Gain (loss) on sale of securities		1,719		(913	)		4,085		(640	)
Other income		1,274		1,825			3,634		4,984

		17,809		12,129			46,108		38,720

General and administrative expenses
Compensation and employee benefits		16,917		14,753			49,711		44,046
Occupancy and equipment		8,019		7,896			22,687		22,387
Data processing		2,549		2,579			7,956		8,228
Consulting		899		1,582			5,076		4,374
Other		9,835		8,425			29,159		26,578

		38,219		35,235			114,589		105,613

Income before minority interests and income taxes		25,116		24,566			69,903		71,106
Minority interests		48		42			114		131
Income taxes		8,440		8,519			23,454		24,102

Income before preferred stock dividends		16,628		16,005			46,335		46,873
Preferred stock dividends		1,353		1,353			4,058		4,058

Net income for common stock	$	15,275	$	14,652		$	42,277	$	42,815

At September 30, 2003, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $0.8 billion.

Disposition of certain debt securities

In June 2000, the Office of Thrift Supervision (OTS) advised ASB that four trust certificates, in the original aggregate principal amount of $114 million, were impermissible investments under regulations applicable to federal savings banks and subsequently required ASB to dispose of the securities. The original trust certificates were purchased through two brokers and represented (i) the right to receive the principal amount of the trust certificates at maturity from an Aaa-rated swap counterparty (principal swap) and (ii) the right to receive the cash flow received on subordinated notes (income notes or equity notes). As a result, ASB recognized interest income on these securities on a cash basis, and in the second quarter of 2000, reclassified these trust certificates from held-to-maturity status to available-for-sale status in its financial statements, recognizing a $3.8 million net loss ($5.8 million pretax) on the writedown of these securities to their then-current estimated fair value. In the first six months of 2001, ASB recognized an additional $4.0 million net loss ($6.2 million pretax) on the writedown of three of these trust certificates to their then-current estimated fair value. In April 2001, ASB sold one of the trust certificates for $30 million, an amount approximating the original purchase price. After PaineWebber Incorporated (PaineWebber) (the broker that sold the remaining three trust certificates to ASB) rejected ASB’s demand that the transactions be rescinded, ASB filed a lawsuit against PaineWebber (described below).

To bring ASB into compliance with the OTS’ directive, ASB directed the trustees to terminate the principal swap component of the three trust certificates and received $43 million from the swaps. Prior to terminating the swaps, ASB had received $2 million of cash from the three trust certificates. After terminating the swaps, the related equity notes were sold by the swap counterparty to HEI, which purchased them only because of the absence of any other buyers and the need to meet the OTS’ demands. In May 2001, HEI purchased two series of the income notes for approximately $21 million and, in July 2001, HEI purchased the third series of income notes for approximately $7 million. As of September 30, 2003, HEI had received $11.4 million of cash from these income notes. The three series of income notes purchased by HEI represent residual equity interests in three entities (Avalon CLO, Pilgrim 1999-01 CLO, and Avalon CLO II) which, as of September 30, 2003, held cash and collateralized corporate debt securities having an estimated par value of approximately $1.7 billion. The entities manage the portfolio of collateralized debt securities, pay expenses and make payments to the various class note holders as specified in the various note agreements. HEI is not the primary beneficiary of these entities. These purchases were made pursuant to the terms of an agreement between HEI and ASB, which, among other things, requires ASB to reimburse HEI for any losses related to the income notes, but only from the proceeds of any recovery from PaineWebber.

Due to the uncertainty of future cash flows, HEI is accounting for the income notes under the cost recovery method of accounting. In the second half of 2001, in 2002 and in the first nine months of 2003, HEI recognized net losses of $5.6 million ($8.7 million pretax), $2.9 million ($4.5 million pretax) and nil, respectively, on the writedown of the three income notes to their then-current estimated fair value based upon an independent third party valuation that is updated quarterly. As of September 30, 2003, the estimated fair value and carrying value (including valuation adjustments totaling $7.4 million recorded in accumulated other comprehensive income) of the income notes totaled approximately $12.1 million. HEI could incur additional losses from the ultimate disposition of these income notes due to further “other-than-temporary” declines in their fair value. HEI’s maximum pre-tax exposure to additional financial statement loss as a result of its ownership of the income notes is $4.7 million as of September 30, 2003.

ASB’s first amended complaint against PaineWebber alleges that, in connection with the sale of the three trust certificates to ASB, PaineWebber (i) violated the Hawaii Uniform Securities Act, (ii) breached fiduciary duties it owed to ASB, (iii) breached express and implied warranties it made to ASB, (iv) made misrepresentations to ASB, and (v) was negligent, and ASB also claims that it is entitled to rescission of the transaction based on mistake. A counterclaim asserted by PaineWebber against ASB alleges violations of the federal securities laws, misrepresentation and fraud and breach of contract and seeks compensatory and punitive damages and attorneys’ fees. Each of the parties has filed multiple motions for partial summary judgment, some of which were heard in January and others were heard in March of 2003. The Court denied all of the motions for summary judgment heard in January, except that it ruled that PaineWebber did not owe a fiduciary duty to ASB with respect to two of the three transactions (which ruling was subsequently vacated by the Court’s subsequent order granting ASB’s motion for reconsideration of that ruling).

On April 25, 2003, the Court issued orders with respect to the motions for partial summary judgment it heard in March. The Court dismissed ASB’s breach of fiduciary duty claim, negligence claim, breach of implied warranty claim and a portion of its misrepresentation claim (to the extent it was based upon certain statements made by PaineWebber), but denied PaineWebber’s motion for partial summary judgment with respect to ASB’s express warranty claim, ASB’s claim for rescission based on mistake and ASB’s common law misrepresentation claim (to the extent it was based on certain other statements made by PaineWebber). The Court had previously ruled that these same representations may be actionable under ASB’s Hawaii securities law claim. In another order the Court ruled that ASB’s recovery of rescissionary damages would be limited to the amount it paid for the trust certificates (about $83.7 million) reduced by the amounts ASB received when the principal portion of the investments were redeemed (about $42.6 million) and when the income notes were sold to HEI (about $27.9 million). The Court’s order does not require an offset for the amount of income ASB received while it held the notes (about $9.4 million). The Court also ruled that ASB would not be entitled (i) to recover any unrealized investment losses and costs that HEI may have suffered after it purchased the income notes, (ii) to recover any element of statutory or other interest, (iii) to invoke rescission (except based upon its statutory claim and claim of mistake) or (iv) to recover compensatory damages with respect to its common law tort claims. At the same time, the Court ruled that ASB may be entitled to recover its attorneys’ fees and punitive damages at trial. Finally, with respect to PaineWebber’s counterclaim, the Court granted ASB’s motion for summary judgment insofar as the counterclaim sought to recover PaineWebber’s costs incurred with respect to its initial communications with the OTS regarding the permissibility of the investments, but denied ASB’s motion for a summary judgment on PaineWebber’s claim that it is entitled to recover the costs it allegedly incurred (less than $0.3 million) with respect to the formal OTS investigation.

Subsequently, PaineWebber filed a renewed motion for summary judgment on ASB’s claim for lost income damages, and ASB moved for reconsideration on several issues. On July 14, 2003, the Court issued orders declining to reconsider its prior orders dismissing certain of ASB’s claims. The Court granted PaineWebber’s renewed motion for partial summary judgment, ruling that ASB is not entitled to recover on its claim for lost income damages. The Court held that the amounts ASB received from HEI reduced the damages that ASB might recover from PaineWebber. ASB and HEI believe this ruling is incorrect.

In light of the Court’s ruling limiting ASB’s ability to recover the damages incurred after HEI purchased the income notes, HEI commenced a separate lawsuit against PaineWebber on September 15, 2003 on the premise that PaineWebber was unjustly enriched if HEI’s purchase of the income notes had the unintended and unwanted consequence of reducing PaineWebber’s liability to ASB. This claim is being pursued without prejudice to ASB’s direct claims and its rights of appeal. PaineWebber has filed a motion to dismiss the HEI lawsuit, which will be heard on January 26, 2004.

Trial of ASB’s case is scheduled to begin in December 2003, before a visiting senior Judge of the U.S. District Court who has been assigned to try the case. Most of the discovery is now completed and only limited pretrial motion work is anticipated prior to trial. The ultimate outcome of the ASB and HEI cases against PaineWebber cannot be determined at this time.

ASB Realty Corporation

In March 1998, ASB formed a subsidiary, ASB Realty Corporation, which elects to be taxed as a real estate investment trust. This reorganization has reduced Hawaii bank franchise taxes, net of federal income taxes, of HEIDI and ASB by $3 million for the nine months ended September 30, 2003 and $17 million for prior years. ASB has taken a dividends received deduction on dividends paid to it by ASB Realty Corporation in the bank franchise tax returns filed in 1999 through 2002. The State of Hawaii Department of Taxation has challenged ASB’s position and has issued notices of tax assessment for 1999, 2000 and 2001. The aggregate amount of tax assessments is approximately $14 million (or $9 million, net of income tax benefits) for tax years 1999 through 2001, plus interest of $3.5 million (or $2.1 million, net of income tax benefits) through September 30, 2003. The interest on the unpaid balance of tax is accruing at a simple interest rate of 8%. Although not yet assessed, the potential bank franchise tax liability for 2002 and 2003 if ASB’s tax position does not prevail is $12 million (or $8 million, net of income tax benefits), plus interest of $0.9 million (or $0.6 million, net of income tax benefits) through September 30, 2003.

In October 2002, ASB filed an appeal with the State Board of Review, First Taxation District (Board). The Board heard ASB’s case on May 13, 2003, and the Board issued its decision in favor of the Department of Taxation on May 19, 2003. As required under Hawaii law, ASB paid the taxes assessed plus interest ($17 million) on June 10, 2003 and filed a notice of appeal with the Hawaii Tax Appeal Court. Trial is schedule to begin in July 2004. ASB believes that its tax position is proper, and the payment of the assessed bank franchise taxes and interest is accordingly being treated like a deposit rather than an expense for financial statement purposes and thus has not affected earnings to date. If it becomes probable that ASB will not prevail on its tax appeal, ASB may be required to write off the deposit and related bank franchise taxes and interest for subsequent years.

Restructuring of Federal Home Loan Bank Advances

In response to pressure on interest rate spreads as a result of the low interest rate environment, ASB restructured a total of $389 million of Federal Home Loan Bank (FHLB) advances during the second quarter of 2003. The restructurings involved paying off existing, higher rate FHLB advances with advances that have lower rates and longer maturities. The restructurings were executed in two transactions, $258 million of advances were restructured in April 2003, and $131 million of advances were restructured in June 2003. In the April 2003 restructuring, the FHLB advances that were paid off had an average rate of 7.17% and an average remaining maturity of 2.02 years. The new advances had an average rate of 5.57% and an average maturity of 4.80 years at the time of the restructuring. The April 2003 restructuring will result in a reduction of interest expense on these FHLB advances of approximately $3 million for 2003. In the June 2003 restructuring, the FHLB advances that were paid off had an average rate of 5.21% and an average remaining maturity of 0.93 years. The new advances had an average rate of 3.21% and an average maturity of 4.12 years at the time of the restructuring. The June 2003 restructuring will result in a reduction of interest expense on these FHLB advances of approximately $1.5 million for 2003. The reduction in interest expense realized through these restructuring transactions will partially offset the reduction in interest income that ASB has been experiencing.

(5) Discontinued operations

HEI Power Corp. (HEIPC)

On October 23, 2001, the HEI Board of Directors adopted a formal plan to exit the international power business (engaged in by HEIPC and its subsidiaries, the HEIPC Group). HEIPC management has been carrying out a program to dispose of all of the HEIPC Group’s remaining projects and investments. Accordingly, the HEIPC Group has been reported as a discontinued operation in the Company’s consolidated statements of income.

As of September 30, 2003, the remaining net assets of the discontinued international power operations amounted to $10 million (included in “Other” assets) and consisted primarily of a $2 million investment in Cagayan Electric Power & Light Co., Inc. (CEPALCO), an electric distribution company in the Philippines, and deferred taxes receivable, reduced by a reserve for losses from operations during the phase-out period. In the second quarter of 2003, HEIPC wrote down its investment in CEPALCO by $5 million (from $7 million to $2 million) and increased its reserve for future expenses by $1 million, primarily for general and administrative expenses during the longer than expected period for completing the disposition of the HEIPC Group’s assets. The reduced valuation of the CEPALCO investment resulted from the deteriorating political and economic environment in the second quarter of 2003 in the Philippines that had significant adverse impacts on business in general and the electric power industry in particular in the Philippines and on the expected financial performance of CEPALCO. The HEIPC Group is currently in substantive negotiations with a potential buyer for HEIPC Philippine Development, LLC, the HEIPC Group company that holds its interest in CEPALCO.

The amounts that HEIPC will ultimately realize from the disposition or sale of the international power assets could differ materially from the recorded amounts and gains or additional losses may be sustained in the future. This could occur, for example, if the HEIPC Group is successful in recovery of the costs incurred in connection with the China joint venture interest or if the investment in CEPALCO is disposed of for less or more than $2 million or if the Internal Revenue Service does not accept HEI’s treatment of the write-off of its indirect investment in East Asia Power Resources Corporation as an ordinary loss for federal corporate income tax purposes. In addition, further losses may be sustained if the expenditures made in seeking recovery of the costs incurred in connection with the China joint

venture interest exceed the total of any recovery ultimately achieved and the amount provided for in HEI’s reserve for discontinued operations.

(6) Cash flows

Supplemental disclosures of cash flow information

For the nine months ended September 30, 2003 and 2002, the Company paid interest amounting to $130.3 million and $145.6 million, respectively.

For the nine months ended September 30, 2003 and 2002, the Company paid income taxes amounting to $13.7 million and $50.6 million, respectively. The lower taxes paid in the first nine months of 2003 compared to the first nine months of 2002 were due to lower estimated 2003 tax payments resulting from the effects of the 2003 federal tax act and tax strategies which deferred 2003 tax payments to later quarters and a change in tax regulations which increased tax payments in 2002 (but did not increase 2002 tax expense).

Supplemental disclosures of noncash activities

Under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP), common stock dividends reinvested by shareholders in HEI common stock in noncash transactions amounted to $13.0 million and $12.3 million for the nine months ended September 30, 2003 and 2002, respectively.

(7) Recent accounting pronouncements and interpretations

Asset retirement obligations

In June 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations,” which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs would be capitalized as part of the carrying amount of the long-lived asset and depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is an obligation of the electric utilities and is settled for other than the carrying amount of the liability, the electric utilities will recognize the difference as a regulatory asset or liability, as the provisions of SFAS No. 143 have no income statement impact for the electric utilities as long as the recovery of the regulatory asset or payment of the regulatory liability is probable. If the obligation is an obligation of a non-electric utility subsidiary and is settled for other than the carrying amount of the liability, such a subsidiary will recognize a gain or loss on settlement. The Company adopted SFAS No. 143 on January 1, 2003 with no effect on the Company’s financial statements.

Rescission of SFAS No. 4, 44 and 64, amendment of SFAS No. 13, and technical corrections

In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” SFAS No. 145 rescinds SFAS No. 4, “Reporting Gains and Losses from Extinguishment of Debt,” SFAS No. 64, “Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements,” and SFAS No. 44, “Accounting for Intangible Assets of Motor Carriers.” SFAS No. 145 also amends SFAS No. 13, “Accounting for Leases,” to eliminate an inconsistency between the required accounting for sale-leaseback transactions and the required accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. SFAS No. 145 also amends other existing authoritative pronouncements to make various technical corrections, clarify meanings, or describe their applicability under changed conditions. The provisions of SFAS No. 145 related to the rescission of SFAS No. 4 are effective for fiscal years beginning after May 15, 2002. The provisions of SFAS No. 145 related to SFAS No. 13 are effective for transactions occurring after May 15, 2002. All other provisions of SFAS No. 145 are effective for financial statements issued on or after May 15, 2002. The Company adopted the provisions of SFAS No. 145 in the second quarter of 2002 with no effect on the Company’s financial statements.

Costs associated with exit or disposal activities

standard include lease termination costs and certain employee severance costs that are associated with a restructuring, discontinued operation, plant closing, or other exit or disposal activity. Previous accounting guidance was provided by Emerging Issues Task Force (EITF) Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring),” which required companies to recognize costs associated with exit or disposal activities at the date of a commitment to an exit or disposal plan. SFAS No. 146 replaces EITF Issue No. 94-3. The Company adopted the provisions of SFAS No. 146 on January 1, 2003. Since SFAS No. 146 applies prospectively to exit or disposal activities initiated after December 31, 2002, the adoption of SFAS No. 146 had no effect on the Company’s historical financial statements.

Guarantor’s accounting and disclosure requirements for guarantees

In November 2002, the FASB issued Interpretation (FIN) No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” which elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements for periods ending after December 15, 2002 about its obligations under guarantees it has issued of the obligations of third parties who are not consolidated in its financial statements. FIN No. 45 also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken. The Company adopted the provisions of FIN No. 45 on January 1, 2003. Since the initial recognition and measurement provisions of FIN No. 45 are applied prospectively to guarantees issued or modified after December 31, 2002, and since HEI and its subsidiaries have not guaranteed the obligations of any entity or person not included in HEI’s consolidated financial statements, the adoption of these provisions of FIN No. 45 had no effect on HEI’s consolidated historical financial statements.

Consolidation of variable interest entities

In January 2003, the FASB issued FIN No. 46, “Consolidation of Variable Interest Entities,” which addresses the consolidation of variable interest entities (VIEs) as defined. FIN No. 46 applies immediately to variable interests in VIEs created after January 31, 2003, and to variable interests in VIEs obtained after January 31, 2003. For a variable interest in a VIE created before February 1, 2003, FIN No. 46 is applied to the enterprise no later than the end of the first interim or annual reporting period ending after December 15, 2003. The disclosures required by FIN No. 46 relating to the income notes purchased by HEI from ASB are included in note (4) and relating to HEI- and HECO-obligated trust preferred securities are included in note (9). The Company will adopt the provisions (other than the already adopted disclosure provisions) of FIN No. 46 relating to VIEs created before February 1, 2003 as of December 31, 2003. Management has not yet determined the impact, if any, of adoption.

Amendment of SFAS No. 133

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” which amends and clarifies financial accounting and reporting for derivative instruments and hedging activities and will result in more consistent reporting of contracts as either derivatives or hybrid instruments. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003 (with some exceptions) and for hedging relationships designated after June 30, 2003. The Company adopted the provisions of SFAS No. 149 on July 1, 2003 with no effect on the Company’s historical financial statements. If ASB acquires derivative instruments or engages in hedging activities as planned, however, SFAS No. 149 may apply prospectively to the financial statements of ASB and its subsidiaries.

Financial instruments with characteristics of both liabilities and equity

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” to establish standards for how an issuer classifies and measures these financial instruments. For example, a financial instrument issued in the form of shares that are mandatorily redeemable would be required by SFAS No. 150 to be classified as a liability. SFAS No. 150 was immediately effective for financial instruments entered into or modified after May 31, 2003. SFAS No. 150 was effective for financial instruments existing as of May 31, 2003 at the beginning of the first interim period beginning after June 15, 2003. In October 2003, however, the FASB indefinitely deferred the effective date of the provisions of SFAS No. 150 related to classification and measurement requirements for mandatorily redeemable financial instruments that become subject to SFAS No. 150 solely as a result of consolidation. The Company adopted the other provisions of SFAS No. 150 for

financial instruments existing as of May 31, 2003 in the third quarter of 2003 and the adoption had no effect on the Company’s financial statements.

Determining whether an arrangement contains a lease

In May 2003, the FASB ratified EITF Issue No. 01-8, “Determining Whether an Arrangement Contains a Lease.” Under EITF Issue No. 01-8, companies may need to recognize service contracts, such as energy contracts for capacity, or other arrangements as leases subject to the requirements of SFAS No. 13, “Accounting for Leases.” The Company adopted the provisions of EITF Issue No. 01-8 in the third quarter of 2003. Since EITF Issue No. 01-8 applies prospectively to arrangements agreed to, modified or acquired after June 30, 2003, the adoption of EITF Issue No. 01-8 had no effect on the Company’s historical financial statements. If any new power purchase agreement or a reassessment of an existing agreement required under certain circumstances (such as in the event of a material amendment of the agreement) falls under the scope of EITF Issue No. 01-8 and SFAS No. 13, and results in the agreement’s classification as a capital lease, a material effect on the Company’s financial statements may result, including the recognition of a significant capital asset and lease obligation.

(8) Commitments and contingencies

See note (4), “Bank subsidiary,” and note (5), “Discontinued operations,” above and note (4), “Commitments and contingencies,” in HECO’s “Notes to consolidated financial statements.”

(9) HEI- and HECO-obligated preferred securities of trust subsidiaries

	September 30, 2003		December 31, 2002		Liquidation value per security
(in thousands, except per security amounts and number of securities)
Hawaiian Electric Industries Capital Trust I* 8.36% Trust Originated Preferred Securities (4,000,000 securities)**	$	100,000	$	100,000	$	25
HECO Capital Trust I* 8.05% Cumulative Quarterly Income Preferred Securities, Series 1997 (2,000,000 securities)***		50,000		50,000		25
HECO Capital Trust II* 7.30% Cumulative Quarterly Income Preferred Securities, Series 1998 (2,000,000 securities)****		50,000		50,000		25

	$	200,000	$	200,000

*	Delaware grantor trust.

**	Fully and unconditionally guaranteed by HEI, no scheduled maturity and currently redeemable at the issuer’s option without premium.

***	Fully and unconditionally guaranteed by HECO; mandatorily redeemable at the maturity of the underlying debt on March 27, 2027, which maturity may be extended to no later than March 27, 2046; and currently redeemable at the issuer’s option without premium.

****	Fully and unconditionally guaranteed by HECO; mandatorily redeemable at the maturity of the underlying debt on December 15, 2028, which maturity may be extended to no later than December 15, 2047; and redeemable at the issuer’s option without premium after December 15, 2003.

Hawaiian Electric Industries Capital Trust I (the Trust) exists for the exclusive purposes of (i) issuing in 1997 trust securities, consisting of 8.36% Trust Originated Preferred Securities ($100 million) and trust common securities ($3 million), (ii) investing the gross proceeds of the trust securities in 8.36% Partnership Preferred Securities issued by HEI Preferred Funding, LP (the Partnership), (iii) making distributions on the Trust Originated Preferred Securities and the trust common securities and (iv) engaging in only those other activities necessary or incidental thereto. All expenses resulting from the limited activities of the Trust, other than the payments by the Trust on its trust preferred securities, have been borne by HEI, either directly or through Hycap Management, Inc. (Hycap), its wholly owned subsidiary.

The Partnership is a Delaware limited partnership managed by Hycap, its sole general partner, and exists for the exclusive purposes of (a) purchasing certain eligible debt instruments of HEI and its subsidiaries (collectively, the

Affiliate Investment Instruments) in the amount of $120 million and certain U.S. government obligations and commercial paper of unaffiliated entities (Eligible Debt Securities) with the proceeds from (i) the 1997 sale of its 8.36% Partnership Preferred Securities to the Trust, its sole limited partner, and (ii) a capital contribution in exchange for the general partner interest, (b) receiving interest and other payments on the Affiliate Investment Instruments and Eligible Debt Securities, (c) making distributions on the 8.36% Partnership Preferred Securities and general partner interest if, as, and when declared by the general partner, (d) making authorized additional investments in Affiliate Investment Instruments and Eligible Debt Securities and disposing of any such investments, and (e) other activities necessary for carrying out the purposes of the Partnership.

Also see note (5), “HECO-obligated mandatorily redeemable preferred securities of trust subsidiaries,” in HECO’s “Notes to consolidated financial statements.”

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated balance sheets (unaudited)

(in thousands, except par value)	September 30, 2003			December 31, 2002
Assets
Utility plant, at cost
Land	$	31,970		$	31,896
Plant and equipment		3,244,532			3,184,818
Less accumulated depreciation		(1,444,863	)		(1,367,954	)
Plant acquisition adjustment, net		263			302
Construction in progress		182,332			164,300

Net utility plant		2,014,234			2,013,362

Current assets
Cash and equivalents		27,381			1,726
Customer accounts receivable, net		88,214			87,113
Accrued unbilled revenues, net		59,681			60,098
Other accounts receivable, net		2,764			2,213
Fuel oil stock, at average cost		38,325			35,649
Materials and supplies, at average cost		23,783			19,450
Prepayments and other		75,349			75,610

Total current assets		315,497			281,859

Other assets
Regulatory assets		105,565			105,568
Unamortized debt expense		14,201			13,354
Long-term receivables and other		18,697			22,243

Total other assets		138,463			141,165

	$	2,468,194		$	2,436,386

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		295,834			295,846
Retained earnings		556,146			542,023

Common stock equity		937,367			923,256
Cumulative preferred stock–not subject to mandatory redemption		34,293			34,293
HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO and HECO-guaranteed debentures		100,000			100,000
Long-term debt, net		698,790			705,270

Total capitalization		1,770,450			1,762,819

Current liabilities
Short-term borrowings–affiliate		—			5,600
Accounts payable		61,848			59,992
Interest and preferred dividends payable		17,349			11,532
Taxes accrued		96,841			79,133
Other		26,124			28,020

Total current liabilities		202,162			184,277

Deferred credits and other liabilities
Deferred income taxes		162,117			158,367
Unamortized tax credits		48,055			47,985
Other		64,168			64,844

Total deferred credits and other liabilities		274,340			271,196

Contributions in aid of construction		221,242			218,094

	$	2,468,194		$	2,436,386

See accompanying notes to HECO’s consolidated financial statements.

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated statements of income (unaudited)

(in thousands, except ratio of earnings to fixed charges)	Three months ended September 30,						Nine months ended September 30,
	2003			2002			2003			2002
Operating revenues	$	358,435		$	332,453		$	1,039,781		$	916,402

Operating expenses
Fuel oil		101,296			85,311			294,303			218,901
Purchased power		92,543			87,123			273,161			240,744
Other operation		37,760			33,888			114,604			95,573
Maintenance		18,025			15,705			47,783			45,727
Depreciation		27,625			26,340			82,870			79,063
Taxes, other than income taxes		33,636			31,287			97,523			88,769
Income taxes		13,974			16,287			36,865			44,110

		324,859			295,941			947,109			812,887

Operating income		33,576			36,512			92,672			103,515

Other income
Allowance for equity funds used during construction		1,098			1,162			3,075			2,977
Other, net		(889	)		858			747			2,435

		209			2,020			3,822			5,412

Income before interest and other charges		33,785			38,532			96,494			108,927

Interest and other charges
Interest on long-term debt		9,973			10,127			30,733			30,430
Amortization of net bond premium and expense		579			498			1,620			1,505
Other interest charges		953			430			1,702			1,313
Allowance for borrowed funds used during construction		(496	)		(549	)		(1,385	)		(1,392	)
Preferred securities distributions of trust subsidiaries		1,918			1,918			5,756			5,756
Preferred stock dividends of subsidiaries		228			228			686			686

		13,155			12,652			39,112			38,298

Income before preferred stock dividends of HECO		20,630			25,880			57,382			70,629
Preferred stock dividends of HECO		270			270			810			810

Net income for common stock	$	20,360		$	25,610		$	56,572		$	69,819

Ratio of earnings to fixed charges (SEC method)								3.23			3.80

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated statements of retained earnings (unaudited)

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2003			2002			2003			2002
Retained earnings, beginning of period	$	549,703		$	520,757		$	542,023		$	495,961
Net income for common stock		20,360			25,610			56,572			69,819
Common stock dividends		(13,917	)		(11,925	)		(42,449	)		(31,338	)

Retained earnings, end of period	$	556,146		$	534,442		$	556,146		$	534,442

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 HECO’s consolidated financial statements.

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated statements of cash flows (unaudited)

Nine months ended September 30	2003			2002
(in thousands)
Cash flows from operating activities
Income before preferred stock dividends of HECO	$	57,382		$	70,629
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities
Depreciation of property, plant and equipment		82,870			79,063
Other amortization		6,216			9,191
Deferred income taxes		3,795			5,081
Tax credits, net		1,197			997
Allowance for equity funds used during construction		(3,075	)		(2,977	)
Changes in assets and liabilities
Increase in accounts receivable		(1,652	)		(40	)
Decrease (increase) in accrued unbilled revenues		417			(5,632	)
Increase in fuel oil stock		(2,676	)		(9,130	)
Increase in materials and supplies		(4,333	)		(1,294	)
Increase in regulatory assets		(2,266	)		(1,386	)
Increase in accounts payable		1,856			953
Increase (decrease) in taxes accrued		17,708			(14,408	)
Changes in other assets and liabilities		7,260			(9,724	)

Net cash provided by operating activities		164,699			121,323

Cash flows from investing activities
Capital expenditures		(83,550	)		(78,217	)
Contributions in aid of construction		10,296			7,394
Other		—			56

Net cash used in investing activities		(73,254	)		(70,767	)

Cash flows from financing activities
Common stock dividends		(42,449	)		(31,338	)
Preferred stock dividends		(810	)		(810	)
Preferred securities distributions of trust subsidiaries		(5,756	)		(5,756	)
Proceeds from issuance of long-term debt		67,360			11,691
Repayment of long-term debt		(74,000	)		(5,000	)
Net decrease in short-term borrowings from affiliate with original maturities of three months or less		(5,600	)		(11,969	)
Other		(4,535	)		(7,339	)

Net cash used in financing activities		(65,790	)		(50,521	)

Net increase in cash and equivalents		25,655			35
Cash and equivalents, beginning of period		1,726			1,858

Cash and equivalents, end of period	$	27,381		$	1,893

See accompanying notes to HECO’s consolidated financial statements.

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 and with 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 Annual Report on SEC Form 10-K for the year ended December 31, 2002 and the unaudited consolidated financial statements and the notes thereto in HEI’s Quarterly Reports on SEC Form 10-Q for the quarters ended March 31, 2003 and June 30, 2003.

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 September 30, 2003 and December 31, 2002, and the results of their operations for the three and nine months ended September 30, 2003 and 2002 and their cash flows for the nine months ended September 30, 2003 and 2002. 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) Revenue taxes

HECO and its subsidiaries’ operating revenues include amounts for various revenue taxes they collect from customers and pay to taxing authorities. Revenue taxes to be paid to the taxing authorities are recorded as an expense and a corresponding liability in the year the related revenues are recognized. Payments to the taxing authorities are made in the subsequent year. For the nine months ended September 30, 2003, HECO and its subsidiaries included $92 million of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense. For the nine months ended September 30, 2002, HECO and its subsidiaries included $82 million of revenue taxes in “operating revenues” and $84 million (including a $2 million nonrecurring PUC fee adjustment) of revenue taxes in “taxes, other than income taxes” expense.

(3) Cash flows

Supplemental disclosures of cash flow information

For the nine months ended September 30, 2003 and 2002, HECO and its subsidiaries paid interest amounting to $26.1 million and $25.4 million, respectively.

For the nine months ended September 30, 2003 and 2002, HECO and its subsidiaries paid income taxes amounting to $15.7 million and $42.8 million, respectively. The lower taxes paid in the first nine months of 2003 compared to the first nine months of 2002 were due to lower estimated 2003 tax payments resulting from the effects of the 2003 federal tax act and tax strategies which deferred 2003 tax payments to later quarters.

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 $3.1 million and $3.0 million for the nine months ended September 30, 2003 and 2002, respectively.

(4) Commitments and contingencies

HELCO power situation

In 1991, Hawaii Electric Light Company, Inc. (HELCO) began planning to meet increased electric generation demand forecast for 1994. HELCO’s plans were to install at its Keahole power plant two 20 megawatt (MW) combustion turbines (CT-4 and CT-5), followed by an 18 MW heat steam recovery 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, which HELCO had planned to install in late 1994. 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.” The PUC at that time also ordered HELCO to continue negotiating with independent power producers (IPPs), stating that the facility to be built should be the one that can be most expeditiously put into service at “allowable cost.”

The timing of the installation of HELCO’s phased units has been revised on several occasions due to delays in obtaining an amendment of a land use permit from the Hawaii Board of Land and Natural Resources (BLNR) and an air permit from the Department of Health of the State of Hawaii (DOH) and the U.S. Environmental Protection Agency (EPA) for the Keahole power plant site. The delays are also attributable to lawsuits, claims and petitions filed by IPPs and other parties challenging these permits and objecting to the expansion, alleging among other things that (1) operation of the expanded Keahole site would not comply with land use regulations (including noise standards) and HELCO’s land patent; (2) HELCO cannot operate the plant within current air quality standards; (3) HELCO could alternatively purchase power from IPPs to meet increased electric generation demand; and (4) HELCO’s land use entitlement expired in April 1999 because it had not completed the project within a three-year construction deadline described below under “Land use permit amendment.”

As a result of a September 19, 2002 decision embodied in an order dated October 3, 2002 and a final judgment dated November 7, 2002 (the November 7, 2002 Final Judgment) by the Third Circuit Court of the State of Hawaii (Circuit Court), relating to an extension of the construction deadline, the construction of CT-4 and CT-5, which had commenced in April 2002 after HELCO had obtained a final air permit and the Circuit Court had lifted a stay on construction, was suspended. HELCO appealed this ruling to the Hawaii Supreme Court and also has been pursuing other options that might allow HELCO to complete the installation of CT-4 and CT-5 (including pursuing settlement through court-ordered mediation in a related proceeding and seeking a land use reclassification of the Keahole site from the Hawaii State Land Use Commission).

On October 14, 2003, the Hawaii Supreme Court granted a motion to remand the pending appeal of the November 7, 2002 Final Judgment to the Circuit Court in order to permit the Circuit Court to consider a proposed motion to vacate that judgment. On October 17, 2003, a motion to vacate the November 7, 2002 Final Judgment was filed by the Keahole Defense Coalition (KDC) and the Hawaii Department of Hawaiian Home Lands (DHHL). The motion was based on an agreement in principle accepted by most, but not all, of the parties to the various proceedings affecting the Keahole power plant and its proposed expansion. HELCO joined in the motion to vacate. The agreement in principle has now been embodied into a settlement agreement (Settlement Agreement) among the participating parties which was signed by the last of the parties to it on November 6, 2003. The Settlement Agreement, which requires HELCO to pursue any further permits which are necessary to complete the plant, will be void if the orders required to effectuate the agreement are not obtained.

Waimana Enterprises, Inc. (Waimana), a named nominal party to the suit in which the November 7, 2002 Final Judgment was entered, did not file briefs in either the underlying Circuit Court case or on appeal of the November 7, 2002 Final Judgment to the Hawaii Supreme Court and chose not to participate in the mediation that led to the Settlement Agreement. However, Waimana opposed the motion filed in the Hawaii Supreme Court to remand the case to the Circuit Court and, on October 31, 2003 filed a memorandum in opposition to the Circuit Court motion of KDC and DHHL to vacate that judgment. Subsequently, on November 5, 2003, Waimana filed a complaint (Federal Complaint) in the United States District Court for the District of Hawaii (U.S. District Court) in which it sought a temporary restraining order and injunction against HELCO, the other parties to the Settlement Agreement and the Hawaii State Judiciary, including among other things a request for an order enjoining the Circuit Court from granting the motion to vacate the November 7, 2002 Final Judgment. Waimana made essentially the same claims before the Hawaii Supreme Court, the Circuit Court and the U.S. District Court, namely that vacating the November 7, 2002 Final Judgment and permitting construction of CT-4 and CT-5 to proceed at the Keahole site would deprive it of alleged property interests without due process and equal protection of the laws and that the Settlement Agreement would not be legally enforceable on a variety of theories.

HELCO and the other parties named in the Federal Complaint filed memoranda and supporting papers in opposition to Waimana’s motion for temporary restraining order and the motion was heard by the U.S. District Court on November 7, 2003. The U.S. District Court denied the motion for temporary restraining order, principally on the ground that a federal court should abstain from interfering with ongoing state court proceedings. The U.S. District Court took under advisement HELCO’S oral motion made at the hearing to dismiss the Federal Complaint.

The motion to vacate the November 7, 2002 Final Judgment was heard by the Circuit Court on November 10, 2003. The Circuit Court judge took the motion to vacate under advisement and indicated his intention to issue his ruling on the motion on November 12, 2003. On November 12, 2003, the motion to vacate the November 7, 2002 Final Judgment was granted. Management cannot predict whether the remaining conditions necessary to implement the Settlement Agreement will be satisfied.

If the remaining conditions of the Settlement Agreement are met, then HELCO will be required to undertake a number of actions to mitigate the impact of the power plant in terms of air and noise pollution, potable water and aesthetic concerns, and construction of CT-4 and CT-5 could be restarted in accordance with the terms of the Settlement Agreement. The actions required of HELCO if the Settlement Agreement is implemented relate to compliance with the stricter 55 dBA (day time) and 45 dBA (night time) noise limitations, additional landscaping, installation of ST-7 with selective catalytic reduction (SCR) emissions control equipment, operation of an existing CT at Keahole within existing air permit limitations rather than the less stringent limitations in a pending air permit revision, primary use of brackish instead of potable water resources, assisting DHHL in installing solar water heating in its housing projects and in obtaining a major part of HELCO’s potable water allocation from the County of Hawaii, facilitating KDC’s participation in certain PUC cases, payment of legal expenses and other costs of various parties to the lawsuits and other proceedings, and cooperation with neighbors and community groups, including a Hot Line service for communications with neighboring DHHL beneficiaries. The BLNR has conditionally granted HELCO’s request for a 19-month extension of the previous December 31, 2003 construction deadline, subject to court action allowing construction to proceed. HELCO anticipates that operational capacity from CT-4 and CT-5 could be available in six to eight months from the time construction is allowed to proceed.

The following is a detailed discussion of the background of the Keahole situation and a description (under “Management’s evaluation; costs incurred”) of its potential financial statement implications.

Land use permit amendment. The Circuit Court ruled in 1997 that because the BLNR had failed to render a valid decision on HELCO’s application to amend its land use permit before the statutory deadline in April 1996, HELCO was entitled to use its Keahole site for the expansion project (HELCO’s “default entitlement”). Final judgments in 1998 of the Circuit Court related to this ruling were appealed to the Hawaii Supreme Court. On July 8, 2003, the Hawaii Supreme Court issued its opinion affirming the Circuit Court’s final judgment on the basis that the BLNR failed to render the necessary four votes either approving or rejecting HELCO’s application. While this opinion validated HELCO’s default entitlement, construction to complete the expansion has been suspended since September 28, 2002 by reason of the ruling eventually embodied in the November 7, 2002 Final Judgment described above.

On July 16, 2003, two parties (Peggy Ratliff and KDC) filed a motion for reconsideration of the Supreme Court’s July 8, 2003 opinion. On August 25, 2003, the Hawaii Supreme Court affirmed its decision.

The Circuit Court’s 1998 final judgment confirming HELCO’s default entitlement provided that HELCO must comply with the conditions in its application and with the standard land use conditions insofar as those conditions were not inconsistent with the default entitlement. There have been numerous proceedings before the Circuit Court and the BLNR in which certain parties (a) have sought determinations of what conditions apply to HELCO’s default entitlement, (b) have claimed that HELCO has not complied with applicable land use conditions and that its default entitlement should thus be forfeited, (c) have claimed that HELCO will not be able to operate the proposed plant without violating applicable land use conditions and provisions of Hawaii’s Air Pollution Control Act and Noise Pollution Act and (d) have sought orders enjoining any further construction at the Keahole site. Although there has not been a final resolution of them, there have been several significant rulings relating to these claims, some of which have adversely affected HELCO’s ability to construct and efficiently operate CT-4 and CT-5 and all of which would be resolved if the Settlement Agreement is implemented.

First, based on a change by the DOH in its interpretation of the noise rules it promulgated under the Hawaii Noise Pollution Act, the Circuit Court ruled that a stricter noise standard than the previously applied standard applies to HELCO’s plant, but left enforcement of the ruling to the DOH. HELCO filed a separate complaint for declaratory relief against the DOH seeking the invalidation of the noise rules on constitutional and other grounds. The Circuit Court denied HELCO’s motion for summary judgment, finding that the noise rules are constitutional on their face but specifically not ruling on the constitutionality of the rules as applied to Keahole. HELCO appealed the final judgment to the Hawaii Supreme Court in August 1999 and a decision on that appeal is pending. The DOH has been periodically monitoring noise levels at the site. If the DOH were to issue a notice of violation based on the stricter standards, HELCO has indicated that it may, among other things, assert that the noise regulations, as applied to it at Keahole, are unconstitutional. While not waiving possible claims or defenses that it might have against the DOH, HELCO has installed noise mitigation measures on the existing units at Keahole. HELCO also has applied to the DOH and received approval for a noise permit through 2003, which has since been extended to July 2007. If the Settlement Agreement is effective, HELCO would not challenge the constitutionality of the stricter noise regulations, as applied to it at Keahole, and would be required to comply with the stricter noise standards during normal

operations, even if it obtains a change in the land use classification of the Keahole site, as described below under “Land Use Commission petition.”

Second, in September 2000, the Circuit Court orally ruled that, absent a legal or equitable extension properly authorized by the BLNR, the three-year construction period in the standard land use conditions of the Department of Land and Natural Resources of the State of Hawaii (DLNR) expired in April 1999. On November 9, 2000, the Circuit Court issued a written ruling to that effect. In December 2000, the Circuit Court granted a motion to stay further construction until extension of the construction deadline is obtained from the BLNR. After conducting a contested case hearing in September 2001, which resulted in the hearings officer recommending an extension be granted, the BLNR, by Order dated March 25, 2002, granted HELCO an extension of the construction deadline through December 31, 2003. The extension was subject to a number of conditions, including, but not limited to, HELCO (1) complying with all applicable laws and with all conditions applicable (a) to the default entitlement, including the 15 standard land use conditions (except where deviations are approved by the BLNR), and (b) to each Conservation District Use Permit (CDUP) and amendment previously awarded to HELCO for this site; (2) agreeing to indemnify and hold the State harmless from claims arising out of any act or omission of HELCO relating to the “permit” (3) proceeding with construction in accordance with construction plans to be submitted to and signed by the chairperson of the BLNR; (4) obtaining approval of the DOH and the Board of Water Supply for any potable water supply or sanitation facilities; (5) complying with its representations relative to mitigation, as set forth in the accepted environmental impact statement; (6) minimizing or eliminating any interference, nuisance or harm which may be caused by this land use; (7) filing, within 90 days of the Order, an application for boundary amendment with the Hawaii State Land Use Commission (LUC) to remove the site from the conservation district; and (8) complying with other terms and conditions as prescribed by the chairperson of the BLNR. The March 25, 2002 Order stated that failure to comply with any of these conditions would render the “permit” void. The March 25, 2002 Order also stated that “no further extensions will be provided.” In April 2002, based on this BLNR decision, the Circuit Court had lifted the stay on construction and construction activities on CT-4 and CT-5 then recommenced.

KDC and two individuals appealed the BLNR’s March 25, 2002 Order to the Circuit Court, as did DHHL. On September 19, 2002, the Circuit Court issued a letter to the parties indicating the Circuit Court’s decision to reverse the BLNR’s Order. The letter stated that:

The BLNR exceeded its statutory authority in granting the extension of the permit. The findings do not support any authority by statute or rule.

The BLNR’s conclusions of law are erroneous.

The BLNR’s action in denying Appellants’ motion to subpoena a material witness regarding a letter issued by the DLNR on January 30, 1998 to HELCO (addressing the applicability of the standard land use conditions and stating that the three-year deadline did not apply) violated Appellants’ constitutional rights to a fair hearing.

The BLNR’s grant of the extension is clearly erroneous in view of the BLNR’s Findings of Fact and Conclusions of Law.

The Circuit Court issued an Order to this effect and final judgment was entered on November 7, 2002. The subsequent history of the November 7, 2002 Final Judgment, including its appeal to the Hawaii Supreme Court, the decision by the Hawaii Supreme Court to remand the case to the Circuit Court and the granting by the Circuit Court of the motion to vacate the judgment, is discussed in detail above.

Third, in other pending litigation, at a hearing on May 8, 2002, the Circuit Court denied the following motions made by KDC and others: a motion for a stay while one of the appeals is pending; a motion for injunction to enjoin construction (based on the allegation that HELCO’s default entitlement is no longer valid); and a motion for preliminary injunction to enjoin construction until the Hawaii Supreme Court decides HELCO’s appeal of the DOH noise regulations and until HELCO demonstrates that the expanded plant can satisfy the noise standards established in 1999 by the Circuit Court. On June 10, 2002, the nonprevailing parties filed a notice of appeal to the Hawaii Supreme Court of the Circuit Court’s decision denying the motion for injunction. The parties have filed briefs in that case. This is one of the pending proceedings that will need to be resolved as a condition to the effectiveness of the Settlement Agreement.

Air permit. In 1997, the DOH issued a final air permit for the Keahole expansion project. Nine appeals of the issuance of the permit were filed with the EPA’s Environmental Appeals Board (EAB). In November 1998, the EAB denied the appeals on most of the grounds stated, but directed the DOH to reopen the permit for limited purposes. The EPA and DOH required additional data collection, which was satisfactorily completed in April 2000. A final air permit was reissued by the DOH in July 2001. Six appeals were filed with the EAB, but those appeals were denied. On November 27, 2001, the final air permit became effective. On September 26, 2003, HELCO filed with the DOH a request for an extension of the maximum time construction may be suspended under the permit.

National Pollutant Discharge Elimination System Permit. Pursuant to EPA and DOH regulations, which took effect in March 2003, all construction sites greater than one acre must obtain a construction stormwater discharge permit. The Keahole site is now subject to this requirement. The DOH issued the permit under its General Permit program in June 2003.

Land Use Commission petition. One of the conditions of the construction period extension granted by the BLNR (which the Circuit Court’s October 3, 2002 Order reversed) was that HELCO file an application for a boundary amendment with the LUC to remove the site from the conservation district. HELCO filed the application on June 21, 2002. A hearing before the LUC was held on September 12, 2002, at which public testimony was taken and memoranda were received regarding the jurisdiction of the LUC in dealing with the HELCO petition. In light of subsequent events, HELCO withdrew its petition on October 3, 2002. Under LUC rules, after such a voluntary withdrawal the applicant may submit another petition for the same property no sooner than one year from the date of withdrawal. HELCO intends to submit a new petition for reclassification in the fourth quarter of 2003, and such a petition is contemplated by the Settlement Agreement. The entire reclassification process could take several years. The installation of ST-7, with SCR as contemplated by the Settlement Agreement, is dependent upon this reclassification.

Management’s evaluation; costs incurred. The probability that HELCO will be allowed to complete the installation of CT-4 and CT-5 during 2004 has been substantially enhanced by the Settlement Agreement, the Circuit Court’s decision on November 12, 2003 to vacate the November 7, 2002 Final Judgment and the decision of the BLNR to extend the construction deadline by 19 months from December 31, 2003. Although the Circuit Court has vacated its November 7, 2002 Final Judgment, there are still additional steps that must be completed under the Settlement Agreement, including requirements that HELCO obtain any further permits necessary to complete the plant. Waimana’s Federal Complaint is still pending and Waimana or other persons may make other attempts to stop the construction and thus there could be further delays in completing construction. In the meantime, one concern of HELCO’s management is the condition and performance of certain aging generators on the HELCO system, which were intended to be retired or to be operated less frequently once CT-4 and CT-5 were installed, as well as the current operating status of various IPPs, which provide approximately 43% of HELCO’s generating capacity under power purchase agreements. Another concern is the possibility of power interruptions under exigent circumstances, including rolling blackouts, as IPPs and/or HELCO’s generating units become unavailable or less available (i.e., available at lower capacity) due to forced outages or planned maintenance. Such incidents occurred or were at risk of occurring on October 3, 2002, November 8, 2002 and July 21, 2003. HELCO will continue its efforts to avert power interruptions through a number of actions (in addition to managing the generating units on its system) such as requesting customers to reduce demand during critical periods like the peak evening hours. There can be no assurance, however, that power interruptions will not occur.

If the conditions related to required payments (excluding capital expenditures) under the Settlement Agreement are satisfied, HELCO would incur approximately $3.1 million in legal and other costs under the Settlement Agreement. Management expects such conditions to be satisfied and to record such payments as expenses in the fourth quarter of 2003. If the remaining conditions in the Settlement Agreement are satisfied, in addition to other capital expenditures to complete CT-4, CT-5 and ST-7, approximately $25 million (approximately $15 million for CT-4 and CT-5, approximately $7 million for ST-7 and approximately $3 million for other existing units) of capital expenditures relating to noise mitigation and air pollution control will be incurred to meet the requirements of the Settlement Agreement.

The recovery of costs relating to CT-4 and CT-5 is subject to the rate-making process governed by the PUC. Management believes no adjustment to costs incurred to put CT-4 and CT-5 into service is required as of September 30, 2003. 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 the costs incurred in its efforts to put these units into service whether or not CT-4 and CT-5 are installed. As of September 30, 2003, HELCO’s costs incurred in its efforts to put CT-4 and CT-5 into service and to support existing units (excluding costs the PUC permitted to be transferred to plant-in-service for pre-air permit facilities) amounted to approximately $84 million, including $32 million for equipment and material purchases, $32 million for planning, engineering, permitting, site development and other costs and $20 million for an allowance for funds used during construction (AFUDC). Substantial additional costs, currently estimated to be approximately $15 million, will be required in order to complete the installations of CT-4 and CT-5, including the costs of satisfying the requirements of the Settlement Agreement pertaining to those units. HELCO has also deferred plans for ST-7 pending obtaining necessary permits, which will be sought promptly, and no costs for ST-7 are included in construction in progress. The costs of ST-7 will be higher than originally planned, not only by reason of the delay in its installation but also by reason of additional costs that will be incurred to satisfy the requirements of the Settlement Agreement.

Although management believes it has acted prudently with respect to the Keahole project, effective December 1, 1998, HELCO discontinued the accrual of AFUDC on CT-4 and CT–5 due in part to the delays through that date and the potential for further delays.

Oahu transmission system

Oahu’s power sources are located primarily in West Oahu. The bulk of HECO’s system load is in the Honolulu/East Oahu area. HECO transmits bulk power to the Honolulu/East Oahu area over two major transmission corridors (Northern and Southern). HECO has for some time planned to construct a part underground/part overhead 138 kilovolt (kV) transmission line from the Kamoku substation to the Pukele substation in order to close the gap between the Southern and Northern corridors and provide a third 138 kV transmission line to the Pukele substation.

Construction of the Kamoku to Pukele transmission line in its originally proposed location required the BLNR to approve a CDUP for the overhead portion of the line that would have been in conservation district lands. Several community and environmental groups opposed the project, particularly the overhead portion of the line.

The BLNR held a public hearing on the CDUP in March 2001, at which several groups requested a contested case hearing, which was held in November 2001. The hearings officer submitted his report, findings of fact and conclusions of law and recommended that HECO’s request for the CDUP be denied. He concluded that HECO had failed to establish that there is a need that outweighs the transmission line’s adverse impacts on conservation district lands and that there are practical alternatives that could be pursued, including an all-underground route outside the conservation district lands. On June 28, 2002, the BLNR issued a ruling denying HECO’s request for the CDUP.

HECO continues to believe that the proposed project (the East Oahu Transmission Project) is needed. The project improves the reliability of the Pukele substation, at the end of the Northern corridor, serving approximately 16% of Oahu’s electrical load, including Waikiki. If one of the 138 kV transmission lines to the Pukele substation fails while the other is out for maintenance, a major system outage would result. The project also would address future potential transmission line overloads in the Northern and Southern corridors under certain contingencies (in which one of the three lines feeding power to the Koolau/Pukele area served by the Northern Corridor, which ends at the Pukele substation, or to the downtown Honolulu area served by the Southern Corridor, is out for maintenance, and a second line incurs an unexpected outage). The line overload contingencies could occur, given current load growth forecasts, in 2005 for the Northern Corridor, but not likely before 2023 in the Southern Corridor.

HECO recently completed its evaluation of alternative ways to accomplish the project. As part of its evaluation, HECO initiated a community-based process to obtain public views of those alternatives. Three primary alternatives have been presented to the community for feedback: (1) an all-underground 138 kV transmission line connecting the Kamoku and Pukele substations; (2) an alternative requiring several new 46 kV underground lines, a new 138-46 kV transformer installed at the Kamoku substation, and equipment modifications at various distribution substations in Honolulu and Waikiki; and (3) an alternative requiring all the work in the preceding 46 kV alternative, plus additional 46 kV underground lines and a new 138-46 kV transformer within the Archer substation. All electrical lines in the three alternatives presented would utilize existing roadways outside of conservation district lands. Each of the alternatives present trade-offs in effectiveness and timeliness in meeting the project objectives, costs, potential construction and other impacts and public feedback.

In October 2003, HECO announced its selection of the third alternative described above. Subject to PUC approval, the project will be built in two phases. Building the project in two phases provides the best opportunity to have a reliable, cost-effective solution in place as soon as possible. Completion of the first phase, targeted for 2006, will address future potential transmission line overloads in the Northern and Southern corridors and improve the reliability of service to many customers in the Pukele substation service area, including Waikiki. The second phase, projected to take an additional two years to complete, will improve service to additional customers in the Pukele substation service area by minimizing the duration of service interruptions under certain contingencies.

Although the underground 138 kV alternative through Palolo valley offers engineering advantages over the long term, it is the most expensive and time consuming of the three alternatives and would leave critical areas of Oahu at risk of blackouts for a projected longer period of time.

As of September 30, 2003, the accumulated costs related to the East Oahu Transmission Project amounted to $19 million, including $13 million for planning, engineering and permitting costs and $6 million for AFUDC. These costs are recorded in construction in progress. The project costs (for both phases, including costs incurred to date) are expected to total between $55 million and $60 million and HECO intends to apply to the PUC for project approval before the end of 2003. The recovery of costs relating to the project is subject to the rate-making process administered by the

PUC. Management believes no adjustment to project costs incurred is required as of September 30, 2003. 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.

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

On April 22 and 23, 2002, HECO and HEI, respectively, were served with an amended complaint filed in the Circuit Court for the First Circuit of Hawaii alleging that the State of Hawaii and HECO’s other customers have been overcharged for electricity as a result of alleged excessive prices in the amended power purchase agreement (PPA) between defendants HECO and AES Hawaii, Inc. (AES Hawaii). AES Hawaii is a subsidiary of The AES Corporation (AES), which guarantees certain obligations of AES Hawaii under the amended PPA.

HECO entered into a PPA with AES Barbers Point, Inc. (now known as AES Hawaii) in March 1988, and the PPA was amended in August 1989. The AES Hawaii 180 MW coal-fired cogeneration plant, which became operational in September 1992, utilizes a “clean-coal” technology and is designed to sell sufficient steam to be a “Qualifying Facility” under the Public Utility Regulatory Policies Act of 1978. The amended PPA, which has a 30-year term, was approved by the PUC in December 1989, following contested case hearings in October 1988, an initial Decision and Order (D&O) in July 1989, an amendment of the PPA in August 1989, and further contested case hearings in November 1989. Intervenors included the state Consumer Advocate and the U.S. Department of Defense. The PUC proceedings addressed a number of issues, including whether the prices for capacity and energy in the amended PPA were less than HECO’s long-term estimated avoided costs, whether HECO needed the capacity to be provided by AES Hawaii, and whether the terms and conditions of the amended PPA were reasonable.

The amended complaint alleged that HECO’s payments to AES Hawaii for power, based on the prices, terms and conditions in the PUC-approved amended PPA, have been “excessive” by over $1 billion since September 1992, and that approval of the amended PPA was wrongfully obtained from the PUC as a result of alleged misrepresentations and/or material omissions by the defendants, individually and/or in conspiracy, with respect to the estimated future costs of the amended PPA versus the costs of hypothetical HECO-owned units. The amended complaint included four claims for relief or causes of action: (1) violations of Hawaii’s Unfair and Deceptive Practices Act, (2) unjust enrichment/restitution, (3) fraud and (4) violation of Hawaii’s False Claim Act, otherwise known as qui tam claims (asserting that the State declined to take over the action). The amended complaint sought treble damages, attorneys’ fees, rescission of the amended PPA and punitive damages against HECO, HEI, AES Hawaii and AES.

On December 20, 2002, HECO and HEI filed a motion to dismiss the amended complaint on the grounds that the plaintiffs’ claims either arose prior to enactment of the Hawaii False Claims Act, which does not have retroactive application, or are barred by the applicable statute of limitations. AES joined in the motion. At a hearing on the motion in early 2003, the First Circuit Court ordered dismissal of the qui tam claims relating to actions prior to May 26, 2000, the effective date of the Hawaii False Claims Act, on the ground that the Act did not have retroactive application. Subsequently, the First Circuit Court issued a minute order dismissing Plaintiffs’ claims for (1) violations of Hawaii’s Unfair and Deceptive Practices Act, (2) unjust enrichment/restitution and (3) fraud, which claims were purportedly brought as a class action, on the ground that all of these claims were barred by the applicable statutes of limitations.

As a result of these rulings by the First Circuit Court, the only remaining claim was under the Hawaii False Claims Act based on allegations that false bills or claims were submitted to the State after May 26, 2000. Under the False Claims Act, a defendant may be liable for treble damages, plus civil penalties of a minimum of $5,000 for each false claim, plus attorneys’ fees and costs incurred in the action.

HECO/HEI filed an answer to the amended complaint on March 17, 2003. On March 20, 2003, HECO and HEI filed a motion for judgment on the pleadings, asking for dismissal of the remaining claims pursuant to the doctrine of primary jurisdiction or, in the alternative, exhaustion of administrative remedies. On April 21, 2003, the court granted in part and denied in part HECO/HEI’s motion for judgment on the pleadings, on the ground that under the doctrine of primary jurisdiction any claims should first be brought before the PUC. The court stayed the action until August 21, 2003, at which time the case would be dismissed if plaintiffs failed to provide proof of having initiated an appropriate PUC proceeding by then. No such proof was provided.

On August 25, 2003, the First Circuit Court issued an order dismissing with prejudice the amended complaint, including all of the Plaintiffs’ remaining claims against the defendants for violations under the Hawaii False Claims Act after May 26, 2000. The final judgment was entered on September 17, 2003. On October 15, 2003, plaintiff Beverly J. Perry filed a notice of appeal to the Hawaii Supreme Court and the Intermediate Court of Appeals, on the grounds that the Circuit Court erred in its reliance on the doctrine of primary jurisdiction and the statute of limitations. AES subsequently filed a cross-appeal of the order denying its motion to dismiss the action, which it had filed on February 24, 2003. HECO and HEI intend to contest plaintiff Perry’s appeal.

Environmental regulation

HECO, HELCO and MECO, like other utilities, periodically identify leaking petroleum-containing equipment and other releases into the environment from its generation plants and other facilities. Each subsidiary reports these releases when and as required by applicable law and addresses impacts due to the releases in compliance with applicable regulatory requirements. Except as otherwise disclosed herein, the Company believes that each subsidiary’s costs of responding to any such releases to date will not have a material adverse effect, individually and in the aggregate, on the Company’s or consolidated HECO’s financial statements.

Honolulu Harbor investigation. In early 1995, the DOH initially advised HECO, Hawaiian Tug & Barge Corp. (HTB), Young Brothers, Limited (YB) and others that it was conducting an investigation to determine the nature and extent of actual or potential releases of hazardous substances, oil, pollutants or contaminants at or near Honolulu Harbor. The DOH issued letters in December 1995 indicating that it had identified a number of parties, including HECO, HTB and YB, who appear to be potentially responsible for the contamination and/or operated their facilities upon contaminated land. The DOH met with these identified parties in January 1996 and certain of the identified parties (including HECO, Chevron Products Company, the State of Hawaii Department of Transportation Harbors Division and others) formed a Honolulu Harbor Work Group (Work Group). Effective January 30, 1998, the Work Group and the DOH entered into a voluntary agreement and scope of work to determine the nature and extent of any contamination, the potentially responsible parties and appropriate remedial actions.

In 1999, the Work Group submitted reports to the DOH presenting environmental conditions and recommendations for additional data gathering to allow for an assessment of the need for risk-based corrective action. The Work Group also engaged a consultant who identified 27 additional potentially responsible parties (PRPs) who were not members of the Work Group, including YB. Under the terms of the 1999 agreement for the sale of YB, HEI and The Old Oahu Tug Service, Inc. (TOOTS) (formerly HTB) have specified indemnity obligations, including obligations with respect to the Honolulu Harbor investigation.

In response to the DOH’s request for technical assistance, the EPA became involved with the harbor investigation in June 2000. In November 2000, the DOH issued notices to over 20 other PRPs, including YB, regarding the ongoing investigation in the Honolulu Harbor area. A new voluntary agreement and a joint defense agreement were signed by the parties in the Work Group and some of the new PRPs, including Phillips Petroleum, but not YB. The group is now called the Iwilei District Participating Parties (Participating Parties). The Participating Parties agreed to fund remediation work using an interim cost allocation method and have organized a limited liability company to perform the work. In September 2001, TOOTS joined the Participating Parties.

In July 2001, the EPA issued a notice of interest (Initial NOI) under the Oil Pollution Act of 1990 to the Participating Parties (including HECO) and others (including YB), regarding the Iwilei Unit of the Honolulu Harbor site. In the Initial NOI, the EPA stated that immediate subsurface investigation and assessment (also known as Rapid Assessment Work) must be conducted to delineate the extent of contamination at the site. The Participating Parties completed the Rapid Assessment Work, submitted a report to the EPA and DOH in January 2002, and developed a proposal for additional investigation (known as the Phase 2 Rapid Assessment Work), which the EPA and DOH approved. The Participating Parties completed the Phase 2 Rapid Assessment Work in the third quarter of 2002. After performing a validation study on the data collected, the Participating Parties submitted a report summarizing the results of the work to the EPA and DOH in April 2003.

In September 2001, the EPA and DOH concurrently issued notices of interest (collectively, the Second NOI) to the members of the Participating Parties, including HECO and TOOTS. The Second NOI identified several investigative and preliminary oil removal tasks to be taken at certain valve control facilities associated with historic

pipelines in the Iwilei Unit of the Honolulu Harbor site. The Participating Parties performed the tasks identified in the Second NOI (the Phase I Pipeline Investigation) and developed a proposal for additional investigation (the Phase 2 Pipeline Investigation), which proposal the EPA and DOH approved. The Participating Parties have completed the Phase 2 Pipeline Investigation and submitted a report summarizing the results of the investigation to the DOH and EPA in March 2003. With the approval of the EPA and DOH, the Participating Parties also constructed a pilot Dual Phase Extraction System to remove petroleum liquids and vapors from the subsurface in a portion of the Iwilei District. Operation of the pilot extraction system began in October 2002. The pilot study supplements ongoing petroleum removal activities by the Participating Parties from wells and trenches installed as part of the investigation. The Participating Parties updated the Conceptual Site Model for the Iwilei Unit and submitted a report (now known as the Site Assessment and Prioritization Report) to the DOH and EPA in April 2003. In addition, the Participating Parties plan to undertake a Feasibility Study during 2003 to identify and evaluate various remedial strategies to address petroleum products identified in the subsurface of the Iwilei District. Based on the Site Assessment and Prioritization Report and the Feasibility Study, the Participating Parties will also recommend implementation of remedial strategies, where appropriate.

In October 2002, HECO and three other companies that currently have petroleum handling operations (the Operating Companies) in the Iwilei Unit entered into an agreement with the DOH to evaluate their facilities to determine whether they currently are releasing petroleum to the subsurface in the Iwilei Unit. Pursuant to the agreement with the DOH, the Operating Companies retained an independent consultant to evaluate each Operating Company’s facilities in the Iwilei Unit. In addition to routinely maintaining its facilities in the Iwilei Unit, HECO had previously investigated its operations and ascertained that they were not releasing petroleum in the Iwilei Unit.

In July 2003, the independent consultant completed and submitted to the DOH and EPA initial reports on each Operating Company’s facilities in the Iwilei Unit. The report on HECO’s facilities confirmed that they are not releasing petroleum in the Iwilei Unit. Based on its evaluation, as well as the EPA, DOH and Operating Company comments, the independent consultant will issue a final report during the fourth quarter of 2003 that identifies, if applicable, deficiencies at Operating Company facilities. If there are deficiencies identified at a facility, the respective Operating Company must develop and implement a work plan to address the deficiencies. In view of the findings in the initial report regarding its facilities, HECO does not anticipate that it will be required to develop and implement such a work plan.

Management has developed a preliminary estimate of costs for continuing investigative work, remedial activities and monitoring at the Iwilei Unit of the site. Management estimates that HECO will incur approximately $1.1 million (of which $0.25 million has been incurred through September 30, 2003) in connection with work to be performed at the site primarily from January 2002 through December 2004. The $1.1 million estimate was expensed in 2001. However, 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 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 after December 2004.

In April 2003, TOOTS, without admitting liability or fault or making any admission of any issue of law or fact, agreed to pay $250,000 to the Participating Parties to fund response activities in the Iwilei Unit, as a one-time cash-out payment in lieu of continuing with further response activities. TOOTS paid the $250,000 in May 2003. The non-cashout parties of the Participating Parties have released and have given covenants not to sue TOOTS, HTB, YB, and Dillingham Tug & Barge Corporation or their respective officers, directors, agents and employees (collectively, TOOTS-Related Entities) under sections of various federal and state environmental laws and any other statute or common law theory (e.g., nuisance or trespass) for any further financial or other contribution towards petroleum and petroleum related response and remediation activities directed or agreed to by the DOH and/or EPA at the site and related business loss and property damage. The non-cashout parties of the Participating Parties have agreed that the payment by TOOTS represents a full and fair resolution of the liability and responsibility of all TOOTS-Related Entities to fund such petroleum and petroleum related response and remediation activities in the Iwilei District of Honolulu.

Maalaea Units 12 and 13 notice and finding of violation. On September 5, 2003, Maui Electric Company, Limited (MECO) received a Notice of Violation (NOV) issued by the DOH alleging violations of opacity conditions in permits issued under the DOH’s Air Pollution Control Law for two generating units at MECO’s Maalaea Power Plant. Opacity measures the impedance of the passage of light through an exhaust plume and is expressed as a percentage (e.g., clear window glass has zero opacity, a brick wall has 100% opacity). The opacity incidents for which the NOV was issued occurred during the period from February 1999 to June 2000. The nature of these generating units causes opacity incidents to occur during unit startup, shutdown and break-in after overhaul. MECO brought the issue to the DOH’s attention in 1998, initiated corrective actions on the two units in 1999, and is currently implementing a compliance plan that was submitted to the DOH in February 2003. The corrective actions have already resulted in a 90% reduction in opacity incidents since the end of 2000. The remaining phases of the compliance plan are aimed at identifying feasible technological controls (i.e., additional corrective actions) to eliminate opacity incidents.

The NOV ordered MECO to immediately take corrective action to prevent further opacity incidents. The NOV also ordered MECO to pay a penalty of $1.6 million (which, if levied and paid, would not be tax deductible), unless MECO submits a written request for a hearing. On September 11, 2003, MECO submitted a request for hearing. In September 2003, MECO accrued $1.6 million for the potential penalty. The NOV specifically addresses opacity incidents that may have occurred at the Maalaea Power Plant between February 1999 and June 2000. The DOH has not indicated if and how it intends to address any other potential incidents at this plant, and therefore management cannot predict their impact.

Collective bargaining agreements

On November 7, 2003, members of the International Brotherhood of Electrical Workers (IBEW), AFL-CIO, Local 1260, Unit 8, ratified new collective bargaining and benefit agreements with HECO, HELCO and MECO. Of the three companies’ approximately 1,860 employees, about 1,100 are members of Unit 8. The new 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, 1.5% on May 1, 2005, 1.5% on November 1, 2005, 1.5% on May 1, 2006, and 3% on November 1, 2006) and include changes to medical, drug, vision and dental plans and increased employee contributions.

(5) HECO-obligated mandatorily redeemable preferred securities of trust subsidiaries

	September 30, 2003		December 31, 2002		Liquidation value per security
(in thousands, except per security amounts and number of securities)
HECO Capital Trust I* 8.05% Cumulative Quarterly Income Preferred Securities, Series 1997 (2,000,000 securities)**	$	50,000	$	50,000	$	25
HECO Capital Trust II* 7.30% Cumulative Quarterly Income Preferred Securities, Series 1998 (2,000,000 securities)***		50,000		50,000		25

	$	100,000	$	100,000

*	Delaware grantor trust and 100%-owned finance subsidiary of HECO.

**	Fully and unconditionally guaranteed by HECO; mandatorily redeemable at the maturity of the underlying debt on March 27, 2027, which maturity may be extended to no later than March 27, 2046; and currently redeemable at the issuer’s option without premium.

***	Fully and unconditionally guaranteed by HECO; mandatorily redeemable at the maturity of the underlying debt on December 15, 2028, which maturity may be extended to no later than December 15, 2047; and redeemable at the issuer’s option after December 15, 2003.

HECO Capital Trust I (Trust I) exists for the exclusive purposes of (i) issuing in 1997 trust securities, consisting of 8.05% Cumulative Quarterly Income Preferred Securities, Series 1997 (1997 Trust Preferred Securities) ($50 million) and trust common securities ($1.5 million to HECO), (ii) investing the proceeds of the trust securities in 8.05% Junior Subordinated Deferrable Interest Debentures, Series 1997 (1997 Debentures) issued by HECO in the principal

amount of $31.5 million and issued by each of MECO and HELCO in the respective principal amounts of $10 million, (iii) making distributions on the 1997 Trust Preferred Securities and trust common securities and (iv) engaging in only those other activities necessary or incidental thereto. The 1997 Debentures, together with HECO’s full and unconditional guarantee of the obligations of MECO and HELCO under their respective debentures, are the sole assets of Trust I.

HECO Capital Trust II (Trust II) exists for the exclusive purposes of (i) issuing in 1998 trust securities, consisting of 7.30% Cumulative Quarterly Income Preferred Securities, Series 1998 (1998 Trust Preferred Securities) ($50 million) and trust common securities ($1.5 million to HECO), (ii) investing the proceeds of the trust securities in 7.30% Junior Subordinated Deferrable Interest Debentures, Series 1998 (1998 Debentures) issued by HECO in the principal amount of $31.5 million and issued by each of MECO and HELCO in the respective principal amounts of $10 million, (iii) making distributions on the 1998 Trust Preferred Securities and trust common securities and (iv) engaging in only those other activities necessary or incidental thereto. The 1998 Debentures, together with HECO’s full and unconditional guarantee of the obligations of MECO and HELCO under their respective debentures, are the sole assets of Trust II.

See note (8) for financial information of Trust I and Trust II.

(6) Recent accounting pronouncements and interpretations

Asset retirement obligations

In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs would be capitalized as part of the carrying amount of the long-lived asset and depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for other than the carrying amount of the liability, HECO and its electric utility subsidiaries will recognize the difference as a regulatory asset or liability, as the provisions of SFAS No. 143 have no income statement impact for a regulated entity as long as the recovery of the regulatory asset or payment of the regulatory liability is probable. HECO and its subsidiaries adopted SFAS No. 143 on January 1, 2003 with no effect on HECO and its subsidiaries’ financial statements.

Rescission of SFAS No. 4, 44 and 64, amendment of SFAS No. 13, and technical corrections

In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” SFAS No. 145 rescinds SFAS No. 4, “Reporting Gains and Losses from Extinguishment of Debt,” SFAS No. 64, “Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements,” and SFAS No. 44, “Accounting for Intangible Assets of Motor Carriers.” SFAS No. 145 also amends SFAS No. 13, “Accounting for Leases,” to eliminate an inconsistency between the required accounting for sale-leaseback transactions and the required accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. SFAS No. 145 also amends other existing authoritative pronouncements to make various technical corrections, clarify meanings, or describe their applicability under changed conditions. The provisions of SFAS No. 145 related to the rescission of SFAS No. 4 are effective for fiscal years beginning after May 15, 2002. The provisions of SFAS No. 145 related to SFAS No. 13 are effective for transactions occurring after May 15, 2002. All other provisions of SFAS No. 145 are effective for financial statements issued on or after May 15, 2002. HECO and its subsidiaries adopted the provisions of SFAS No. 145 in the second quarter of 2002 with no effect on HECO and its subsidiaries’ financial statements.

Costs associated with exit or disposal activities

In July 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. Examples of costs covered by the standard include lease termination costs and certain employee severance costs that are associated with a restructuring, discontinued operation, plant closing, or other exit or disposal activity. Previous accounting guidance was provided by EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring),” which required companies to

recognize costs associated with exit or disposal activities at the date of a commitment to an exit or disposal plan. SFAS No. 146 replaces EITF Issue No. 94-3. HECO and its subsidiaries adopted the provisions of SFAS No. 146 on January 1, 2003. Since SFAS No. 146 applies prospectively to exit or disposal activities initiated after December 31, 2002, the adoption of SFAS No. 146 had no effect on HECO and its subsidiaries’ historical financial statements.

Guarantor’s accounting and disclosure requirements for guarantees

In November 2002, the FASB issued FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” which elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements for periods ending after December 15, 2002 about its obligations under guarantees it has issued of the obligations of third parties who are not consolidated in its financial statements. FIN No. 45 also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken. HECO and its subsidiaries adopted the provisions of FIN No. 45 on January 1, 2003. Since the initial recognition and measurement provisions of FIN No. 45 are applied prospectively to guarantees issued or modified after December 31, 2002, and since HECO and its subsidiaries have not guaranteed the obligations of any entity or person not included in HECO’s consolidated financial statements, the adoption of these provisions of FIN No. 45 had no effect on HECO’s consolidated historical financial statements.

Consolidation of variable interest entities

In January 2003, the FASB issued FIN No. 46, “Consolidation of Variable Interest Entities,” which addresses the consolidation of VIEs as defined. FIN No. 46 applies immediately to variable interests in VIEs created after January 31, 2003, and to variable interests in VIEs obtained after January 31, 2003. For a variable interest in a VIE created before February 1, 2003, FIN No. 46 is applied to the enterprise no later than the end of the first interim or annual reporting period ending after December 15, 2003. The disclosures required by FIN No. 46 relating to HECO-obligated trust preferred securities are included in note (5). HECO and its subsidiaries will adopt the provisions (other than the already adopted disclosure provisions) of FIN No. 46 relating to VIEs created before February 1, 2003 as of December 31, 2003. Management has not yet determined the impact, if any, of adoption.

Financial instruments with characteristics of both liabilities and equity

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” to establish standards for how an issuer classifies and measures these financial instruments. For example, a financial instrument issued in the form of shares that are mandatorily redeemable would be required by SFAS No. 150 to be classified as a liability. SFAS No. 150 was immediately effective for financial instruments entered into or modified after May 31, 2003. SFAS No. 150 was effective for financial instruments existing as of May 31, 2003 at the beginning of the first interim period beginning after June 15, 2003. In October 2003, however, the FASB indefinitely deferred the effective date of the provisions of SFAS No. 150 related to classification and measurement requirements for mandatorily redeemable financial instruments that become subject to SFAS No. 150 solely as a result of consolidation. HECO and its subsidiaries adopted the other provisions of SFAS No. 150 for financial instruments existing as of May 31, 2003 in the third quarter of 2003 and the adoption had no effect on the consolidated HECO’s financial statements.

Determining whether an arrangement contains a lease

In May 2003, the FASB ratified EITF Issue No. 01-8, “Determining Whether an Arrangement Contains a Lease.” Under EITF Issue No. 01-8, companies may need to recognize service contracts, such as energy contracts for capacity, or other arrangements as leases subject to the requirements of SFAS No. 13, “Accounting for Leases.” HECO and its subsidiaries adopted the provisions of EITF Issue No. 01-8 in the third quarter of 2003. Since EITF Issue No. 01-8 applies prospectively to arrangements agreed to, modified or acquired after June 30, 2003, the adoption of EITF Issue No. 01-8 had no effect on consolidated HECO’s historical financial statements. If any new power purchase agreement or a reassessment of an existing agreement required under certain circumstances (such as in the event of a material amendment of the agreement) falls under the scope of EITF Issue No. 01-8 and SFAS No. 13, and results in the agreement’s classification as a capital lease, a material effect on HECO’s consolidated financial statements may result, including the recognition of a significant capital asset and lease obligation.

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

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2003			2002			2003			2002
Operating income from HECO consolidated regulated and nonregulated activities before income taxes (per HEI consolidated statements of income)	$	46,636		$	53,589		$	130,196		$	150,146
Deduct:
Income taxes on regulated activities		(13,974	)		(16,287	)		(36,865	)		(44,110	)
Revenues from nonregulated activities		(815	)		(1,183	)		(2,910	)		(3,241	)
Add:
Expenses from nonregulated activities		1,729			393			2,251			720

Operating income from regulated activities after income taxes (per HECO consolidated statements of income)	$	33,576		$	36,512		$	92,672		$	103,515

(8) Consolidating financial information

HECO is not required to provide separate financial statements and other disclosures concerning HELCO and MECO to holders of the 1997 and 1998 junior deferrable debentures issued by HELCO and MECO since these securities have been fully and unconditionally guaranteed, on a subordinated basis, by HECO and consolidating information is provided for these and other HECO subsidiaries. HECO also unconditionally guarantees HELCO’s and MECO’s obligations (a) to the State of Hawaii for the repayment of principal and interest on their Special Purpose Revenue Bonds and (b) relating to the trust preferred securities of HECO Capital Trust I and HECO Capital Trust II. HECO is also obligated 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.

For consolidating financial information for HECO and its subsidiaries for the periods ended and as of the dates indicated, see pages 32 through 39. As of December 31, 2002 and for the three and nine months ended September 30, 2002, there were no amounts for HECO subsidiary Renewable Hawaii, Inc.

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating balance sheet (unaudited)

September 30, 2003

(in thousands)	HECO			HELCO		MECO		RHI		HECO Capital Trust I	HECO Capital Trust II	Reclassi- fications and elimina- tions		HECO consoli- dated
Assets
Utility plant, at cost
Land	$	25,378		3,006		3,586		—		—	—	—		$	31,970
Plant and equipment		2,060,272		578,799		605,461		—		—	—	—			3,244,532
Less accumulated depreciation		(918,030	)	(269,257	)	(257,576	)	—		—	—	—			(1,444,863	)
Plant acquisition adjustment, net		—		—		263		—		—	—	—			263
Construction in progress		76,797		96,792		8,743		—		—	—	—			182,332

Net utility plant		1,244,417		409,340		360,477		—		—	—	—			2,014,234

Investment in wholly owned subsidiaries, at equity		363,932		—		—		—		—	—	(363,932	)		—

Current assets
Cash and equivalents		21,774		1,270		4,268		69		—	—	—			27,381
Advances to affiliate		9,500		—		28,000		—		51,546	51,546	(140,592	)		—
Customer accounts receivable, net		60,019		15,146		13,049		—		—	—	—			88,214
Accrued unbilled revenues, net		41,098		10,303		8,280		—		—	—	—			59,681
Other accounts receivable, net		2,493		571		327		—		—	—	(627	)		2,764
Fuel oil stock, at average cost		27,546		3,896		6,883		—		—	—	—			38,325
Materials and supplies, at average cost		11,926		2,523		9,334		—		—	—	—			23,783
Prepayments and other		61,501		9,232		4,616		—		—	—	—			75,349

Total current assets		235,857		42,941		74,757		69		51,546	51,546	(141,219	)		315,497

Other assets
Regulatory assets		75,428		16,332		13,805		—		—	—	—			105,565
Unamortized debt expense		8,347		2,968		2,886		—		—	—	—			14,201
Long-term receivables and other		12,579		3,592		2,526		—		—	—	—			18,697

Total other assets		96,354		22,892		19,217		—		—	—	—			138,463

	$	1,940,560		475,173		454,451		69		51,546	51,546	(505,151	)	$	2,468,194


Capitalization and liabilities
Capitalization
Common stock equity	$	937,367		176,007		184,725		108		1,546	1,546	(363,932	)	$	937,367
Cumulative preferred stock-not subject to mandatory redemption		22,293		7,000		5,000		—		—	—	—			34,293
HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO and HECO-guaranteed debentures		—		—		—		—		50,000	50,000	—			100,000
Long-term debt, net		497,308		140,857		163,717		—		—	—	(103,092	)		698,790

Total capitalization		1,456,968		323,864		353,442		108		51,546	51,546	(467,024	)		1,770,450

Current liabilities
Short-term borrowings-affiliate		28,000		9,500		—		—		—	—	(37,500	)		—
Accounts payable		45,651		9,876		6,321		—		—	—	—			61,848
Interest and preferred dividends payable		10,676		2,778		3,925		—		—	—	(30	)		17,349
Taxes accrued		57,732		16,586		22,523		—		—	—	—			96,841
Other		18,409		2,276		6,029		7		—	—	(597	)		26,124

Total current liabilities		160,468		41,016		38,798		7		—	—	(38,127	)		202,162

Deferred credits and other liabilities
Deferred income taxes		133,600		17,732		10,831		(46	)	—	—	—			162,117
Unamortized tax credits		28,518		8,690		10,847		—		—	—	—			48,055
Other		21,749		27,540		14,879		—		—	—	—			64,168

Total deferred credits and other liabilities		183,867		53,962		36,557		(46	)	—	—	—			274,340

Contributions in aid of construction		139,257		56,331		25,654		—		—	—	—			221,242

	$	1,940,560		475,173		454,451		69		51,546	51,546	(505,151	)	$	2,468,194

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating balance sheet (unaudited)

December 31, 2002

(in thousands)	HECO			HELCO		MECO		HECO Capital Trust I	HECO Capital Trust II	Reclassi- fications and elimina- tions		HECO consoli- dated
Assets
Utility plant, at cost
Land	$	25,329		2,982		3,585		—	—	—		$	31,896
Plant and equipment		2,022,987		565,920		595,911		—	—	—			3,184,818
Less accumulated depreciation		(872,332	)	(255,473	)	(240,149	)	—	—	—			(1,367,954	)
Plant acquisition adjustment, net		—		—		302		—	—	—			302
Construction in progress		63,246		93,428		7,626		—	—	—			164,300

Net utility plant		1,239,230		406,857		367,275		—	—	—			2,013,362

Investment in wholly owned subsidiaries, at equity		355,869		—		—		—	—	(355,869	)		—

Current assets
Cash and equivalents		9		4		1,713		—	—	—			1,726
Advances to affiliate		14,900		—		23,000		51,546	51,546	(140,992	)		—
Customer accounts receivable, net		61,384		13,979		11,750		—	—	—			87,113
Accrued unbilled revenues, net		41,272		10,701		8,125		—	—	—			60,098
Other accounts receivable, net		2,582		411		462		—	—	(1,242	)		2,213
Fuel oil stock, at average cost		25,701		3,446		6,502		—	—	—			35,649
Materials and supplies, at average cost		9,076		2,248		8,126		—	—	—			19,450
Prepayments and other		61,108		9,457		5,045		—	—	—			75,610

Total current assets		216,032		40,246		64,723		51,546	51,546	(142,234	)		281,859

Other assets
Regulatory assets		74,946		16,557		14,065		—	—	—			105,568
Unamortized debt expense		8,952		1,915		2,487		—	—	—			13,354
Long-term receivables and other		15,540		3,406		3,297		—	—	—			22,243

Total other assets		99,438		21,878		19,849		—	—	—			141,165

	$	1,910,569		468,981		451,847		51,546	51,546	(498,103	)	$	2,436,386

Capitalization and liabilities
Capitalization
Common stock equity	$	923,256		171,404		181,373		1,546	1,546	(355,869	)	$	923,256
Cumulative preferred stock-not subject to mandatory redemption		22,293		7,000		5,000		—	—	—			34,293
HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO and HECO-guaranteed debentures		—		—		—		50,000	50,000	—			100,000
Long-term debt, net		495,689		140,993		171,680		—	—	(103,092	)		705,270

Total capitalization		1,441,238		319,397		358,053		51,546	51,546	(458,961	)		1,762,819

Current liabilities
Short-term borrowings-affiliate		28,600		14,900		—		—	—	(37,900	)		5,600
Accounts payable		41,594		10,462		7,936		—	—	—			59,992
Interest and preferred dividends payable		7,537		1,598		2,435		—	—	(38	)		11,532
Taxes accrued		48,274		14,898		15,961		—	—	—			79,133
Other		20,998		3,679		4,547		—	—	(1,204	)		28,020

Total current liabilities		147,003		45,537		30,879		—	—	(39,142	)		184,277

Deferred credits and other liabilities
Deferred income taxes		132,159		14,479		11,729		—	—	—			158,367
Unamortized tax credits		28,430		8,471		11,084		—	—	—			47,985
Other		23,441		26,809		14,594		—	—	—			64,844

Total deferred credits and other liabilities		184,030		49,759		37,407		—	—	—			271,196

Contributions in aid of construction		138,298		54,288		25,508		—	—	—			218,094

	$	1,910,569		468,981		451,847		51,546	51,546	(498,103	)	$	2,436,386

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating statement of income (unaudited)

Three months ended September 30, 2003

(in thousands)	HECO			HELCO		MECO		RHI		HECO Capital Trust I	HECO Capital Trust II	Reclassi- fications and elimina- tions		HECO consoli- dated
Operating revenues	$	249,792		53,799		54,844		—		—	—	—		$	358,435

Operating expenses
Fuel oil		72,589		7,634		21,073		—		—	—	—			101,296
Purchased power		71,408		19,274		1,861		—		—	—	—			92,543
Other operation		25,269		5,658		6,833		—		—	—	—			37,760
Maintenance		10,430		4,106		3,489		—		—	—	—			18,025
Depreciation		16,781		5,057		5,787		—		—	—	—			27,625
Taxes, other than income taxes		23,392		5,071		5,173		—		—	—	—			33,636
Income taxes		9,043		1,845		3,086		—		—	—	—			13,974

		228,912		48,645		47,302		—		—	—	—			324,859

Operating income		20,880		5,154		7,542		—		—	—	—			33,576

Other income
Allowance for equity funds used during construction		921		64		113		—		—	—	—			1,098
Equity in earnings of subsidiaries		6,292		—		—		—		—	—	(6,292	)		—
Other, net		635		73		(1,498	)	(8	)	1,037	941	(2,069	)		(889	)

		7,848		137		(1,385	)	(8	)	1,037	941	(8,361	)		209

Income before interest and other charges		28,728		5,291		6,157		(8	)	1,037	941	(8,361	)		33,785

Interest and other charges
Interest on long-term debt		6,228		1,672		2,073		—		—	—	—			9,973
Amortization of net bond premium and expense		374		100		105		—		—	—	—			579
Other interest charges		1,916		538		567		—		—	—	(2,068	)		953
Allowance for borrowed funds used during construction		(420	)	(32	)	(44	)	—		—	—	—			(496	)
Preferred securities distributions of trust subsidiaries		—		—		—		—		—	—	1,918			1,918
Preferred stock dividends of subsidiaries		—		—		—		—		—	—	228			228

		8,098		2,278		2,701		—		—	—	78			13,155

Income before preferred stock dividends of HECO		20,630		3,013		3,456		(8	)	1,037	941	(8,439	)		20,630
Preferred stock dividends of HECO		270		133		95		—		1,006	912	(2,146	)		270

Net income for common stock	$	20,360		2,880		3,361		(8	)	31	29	(6,293	)	$	20,360

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating statement of retained earnings (unaudited)

Three months ended September 30, 2003

(in thousands)	HECO			HELCO		MECO		RHI		HECO Capital Trust I		HECO Capital Trust II		Reclassi- fications and elimina- tions		HECO consoli- dated
Retained earnings, beginning of period	$	549,703		73,963		89,836		(64	)	—		—		(163,735	)	$	549,703
Net income for common stock		20,360		2,880		3,361		(8	)	31		29		(6,293	)		20,360
Common stock dividends		(13,917	)	(1,480	)	(3,386	)	—		(31	)	(29	)	4,926			(13,917	)

Retained earnings, end of period	$	556,146		75,363		89,811		(72	)	—		—		(165,102	)	$	556,146

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating statement of income (unaudited)

Three months ended September 30, 2002

(in thousands)	HECO			HELCO		MECO		HECO Capital Trust I	HECO Capital Trust II	Reclassi- fications and elimina- tions		HECO consoli- dated
Operating revenues	$	232,636		49,156		50,661		—	—	—		$	332,453

Operating expenses
Fuel oil		59,602		8,083		17,626		—	—	—			85,311
Purchased power		70,300		14,726		2,097		—	—	—			87,123
Other operation		22,423		5,037		6,428		—	—	—			33,888
Maintenance		10,474		2,688		2,543		—	—	—			15,705
Depreciation		15,904		4,870		5,566		—	—	—			26,340
Taxes, other than income taxes		21,829		4,642		4,816		—	—	—			31,287
Income taxes		10,169		2,632		3,486		—	—	—			16,287

		210,701		42,678		42,562		—	—	—			295,941

Operating income		21,935		6,478		8,099		—	—	—			36,512

Other income
Allowance for equity funds used during construction		1,042		59		61		—	—	—			1,162
Equity in earnings of subsidiaries		9,643		—		—		—	—	(9,643	)		—
Other, net		879		69		33		1,037	941	(2,101	)		858

		11,564		128		94		1,037	941	(11,744	)		2,020

Income before interest and other charges		33,499		6,606		8,193		1,037	941	(11,744	)		38,532

Interest and other charges
Interest on long-term debt		6,113		1,809		2,205		—	—	—			10,127
Amortization of net bond premium and expense		322		78		98		—	—	—			498
Other interest charges		1,676		518		337		—	—	(2,101	)		430
Allowance for borrowed funds used during construction		(492	)	(32	)	(25	)	—	—	—			(549	)
Preferred securities distributions of trust subsidiaries		—		—		—		—	—	1,918			1,918
Preferred stock dividends of subsidiaries		—		—		—		—	—	228			228

		7,619		2,373		2,615		—	—	45			12,652

Income before preferred stock dividends of HECO		25,880		4,233		5,578		1,037	941	(11,789	)		25,880
Preferred stock dividends of HECO		270		133		95		1,006	912	(2,146	)		270

Net income for common stock	$	25,610		4,100		5,483		31	29	(9,643	)	$	25,610

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating statement of retained earnings (unaudited)

Three months ended September 30, 2002

(in thousands)	HECO			HELCO		MECO		HECO Capital Trust I		HECO Capital Trust II		Reclassi- fications and elimina- tions		HECO consoli- dated
Retained earnings, beginning of period	$	520,757		70,616		82,617		—		—		(153,233	)	$	520,757
Net income for common stock		25,610		4,100		5,483		31		29		(9,643	)		25,610
Common stock dividends		(11,925	)	(2,108	)	(2,198	)	(31	)	(29	)	4,366			(11,925	)

Retained earnings, end of period	$	534,442		72,608		85,902		—		—		(158,510	)	$	534,442

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating statement of income (unaudited)

Nine months ended September 30, 2003

(in thousands)	HECO			HELCO		MECO		RHI		HECO Capital Trust I	HECO Capital Trust II	Reclassi- fications and elimina- tions		HECO consoli- dated
Operating revenues	$	722,316		157,791		159,674		—		—	—	—		$	1,039,781

Operating expenses
Fuel oil		208,977		23,964		61,362		—		—	—	—			294,303
Purchased power		212,575		54,476		6,110		—		—	—	—			273,161
Other operation		77,063		17,312		20,229		—		—	—	—			114,604
Maintenance		30,018		9,005		8,760		—		—	—	—			47,783
Depreciation		50,340		15,171		17,359		—		—	—	—			82,870
Taxes, other than income taxes		67,670		14,823		15,030		—		—	—	—			97,523
Income taxes		21,684		6,242		8,939		—		—	—	—			36,865

		668,327		140,993		137,789		—		—	—	—			947,109

Operating income		53,989		16,798		21,885		—		—	—	—			92,672

Other income
Allowance for equity funds used during construction		2,624		152		299		—		—	—	—			3,075
Equity in earnings of subsidiaries		22,415		—		—		—		—	—	(22,415	)		—
Other, net		2,268		234		(1,389	)	(71	)	3,112	2,822	(6,229	)		747

		27,307		386		(1,090	)	(71	)	3,112	2,822	(28,644	)		3,822

Income before interest and other charges		81,296		17,184		20,795		(71	)	3,112	2,822	(28,644	)		96,494

Interest and other charges
Interest on long-term debt		19,059		5,350		6,324		—		—	—	—			30,733
Amortization of net bond premium and expense		1,039		276		305		—		—	—	—			1,620
Other interest charges		5,010		1,509		1,410		1		—	—	(6,228	)		1,702
Allowance for borrowed funds used during construction		(1,194	)	(73	)	(118	)	—		—	—	—			(1,385	)
Preferred securities distributions of trust subsidiaries		—		—		—		—		—	—	5,756			5,756
Preferred stock dividends of subsidiaries		—		—		—		—		—	—	686			686

		23,914		7,062		7,921		1		—	—	214			39,112

Income before preferred stock dividends of HECO		57,382		10,122		12,874		(72	)	3,112	2,822	(28,858	)		57,382
Preferred stock dividends of HECO		810		400		286		—		3,019	2,737	(6,442	)		810

Net income for common stock	$	56,572		9,722		12,588		(72	)	93	85	(22,416	)	$	56,572

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating statement of retained earnings (unaudited)

Nine months ended September 30, 2003

(in thousands)	HECO			HELCO		MECO		RHI		HECO Capital Trust I		HECO Capital Trust II		Reclassi- fications and elimina- tions		HECO consoli- dated
Retained earnings, beginning of period	$	542,023		71,414		87,092		—		—		—		(158,506	)	$	542,023
Net income for common stock		56,572		9,722		12,588		(72	)	93		85		(22,416	)		56,572
Common stock dividends		(42,449	)	(5,773	)	(9,869	)	—		(93	)	(85	)	15,820			(42,449	)

Retained earnings, end of period	$	556,146		75,363		89,811		(72	)	—		—		(165,102	)	$	556,146

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating statement of income (unaudited)

Nine months ended September 30, 2002

(in thousands)	HECO			HELCO		MECO		HECO Capital Trust I	HECO Capital Trust II	Reclassi- fications and elimina- tions		HECO consoli- dated

Operating revenues	$	634,262		140,631		141,509		—	—	—		$	916,402

Operating expenses
Fuel oil		151,544		21,370		45,987		—	—	—			218,901
Purchased power		192,814		42,509		5,421		—	—	—			240,744
Other operation		60,865		15,289		19,419		—	—	—			95,573
Maintenance		29,591		7,098		9,038		—	—	—			45,727
Depreciation		47,708		14,658		16,697		—	—	—			79,063
Taxes, other than income taxes		61,374		13,617		13,778		—	—	—			88,769
Income taxes		27,647		7,447		9,016		—	—	—			44,110

		571,543		121,988		119,356		—	—	—			812,887

Operating income		62,719		18,643		22,153		—	—	—			103,515

Other income
Allowance for equity funds used during construction		2,680		168		129		—	—	—			2,977
Equity in earnings of subsidiaries		25,935		—		—		—	—	(25,935	)		—
Other, net		2,477		256		33		3,112	2,822	(6,265	)		2,435

		31,092		424		162		3,112	2,822	(32,200	)		5,412

Income before interest and other charges		93,811		19,067		22,315		3,112	2,822	(32,200	)		108,927

Interest and other charges
Interest on long-term debt		18,356		5,460		6,614		—	—	—			30,430
Amortization of net bond premium and expense		962		243		300		—	—	—			1,505
Other interest charges		5,110		1,467		1,001		—	—	(6,265	)		1,313
Allowance for borrowed funds used during construction		(1,246	)	(91	)	(55	)	—	—	—			(1,392	)
Preferred securities distributions of trust subsidiaries		—		—		—		—	—	5,756			5,756
Preferred stock dividends of subsidiaries		—		—		—		—	—	686			686

		23,182		7,079		7,860		—	—	177			38,298

Income before preferred stock dividends of HECO		70,629		11,988		14,455		3,112	2,822	(32,377	)		70,629
Preferred stock dividends of HECO		810		400		286		3,019	2,737	(6,442	)		810

Net income for common stock	$	69,819		11,588		14,169		93	85	(25,935	)	$	69,819

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating statement of retained earnings (unaudited)

Nine months ended September 30, 2002

(in thousands)	HECO			HELCO		MECO		HECO Capital Trust I		HECO Capital Trust II		Reclassi- fications and elimina- tions		HECO consoli- dated
Retained earnings, beginning of period	$	495,961		65,690		78,182		—		—		(143,872	)	$	495,961
Net income for common stock		69,819		11,588		14,169		93		85		(25,935	)		69,819
Common stock dividends		(31,338	)	(4,670	)	(6,449	)	(93	)	(85	)	11,297			(31,338	)

Retained earnings, end of period	$	534,442		72,608		85,902		—		—		(158,510	)	$	534,442

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating statement of cash flows (unaudited)

Nine months ended September 30, 2003

(in thousands)	HECO			HELCO		MECO		RHI		HECO Capital Trust I		HECO Capital Trust II		Elimination addition to (deduction from) cash flows		HECO consolidated
Cash flows from operating activities
Income before preferred stock dividends of HECO	$	57,382		10,122		12,874		(72	)	3,112		2,822		(28,858	)	$	57,382
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities
Equity in earnings		(22,415	)	—		—		—		—		—		22,415			—
Common stock dividends received from subsidiaries		15,819		—		—		—		—		—		(15,819	)		—
Depreciation of property, plant and equipment		50,340		15,171		17,359		—		—		—		—			82,870
Other amortization		2,991		569		2,656		—		—		—		—			6,216
Deferred income taxes		1,485		3,252		(896	)	(46	)	—		—		—			3,795
Tax credits, net		853		388		(44	)	—		—		—		—			1,197
Allowance for equity funds used during construction		(2,624	)	(152	)	(299	)	—		—		—		—			(3,075	)
Changes in assets and liabilities
Decrease (increase) in accounts receivable		1,454		(1,327	)	(1,164	)	—		—		—		(615	)		(1,652	)
Decrease (increase) in accrued unbilled revenues		174		398		(155	)	—		—		—		—			417
Increase in fuel oil stock		(1,845	)	(450	)	(381	)	—		—		—		—			(2,676	)
Increase in materials and supplies		(2,850	)	(275	)	(1,208	)	—		—		—		—			(4,333	)
Decrease (increase) in regulatory assets		(543	)	408		(2,131	)	—		—		—		—			(2,266	)
Increase (decrease) in accounts payable		4,057		(586	)	(1,615	)	—		—		—		—			1,856
Increase in taxes accrued		9,458		1,688		6,562		—		—		—		—			17,708
Changes in other assets and liabilities		(1,696	)	(1,403	)	3,982		6		—		—		6,371			7,260

Net cash provided by (used in) operating activities		112,040		27,803		35,540		(112	)	3,112		2,822		(16,506	)		164,699

Cash flows from investing activities
Capital expenditures		(53,805	)	(18,770	)	(10,975	)	—		—		—		—			(83,550	)
Contribution in aid of construction		5,028		4,120		1,148		—		—		—		—			10,296
Investment in subsidiary		(181	)	—		—		—		—		—		181			—
Advances to (repayments from) affiliates		5,400		—		(5,000	)	—		—		—		(400	)		—

Net cash used in investing activities		(43,558	)	(14,650	)	(14,827	)	—		—		—		(219	)		(73,254	)

Cash flows from financing activities
Common stock dividends		(42,449	)	(5,773	)	(9,869	)	—		(93	)	(85	)	15,820			(42,449	)
Preferred stock dividends		(810	)	(400	)	(286	)	—		—		—		686			(810	)
Preferred securities distributions of trust subsidiaries		—		—		—		—		(3,019	)	(2,737	)	—			(5,756	)
Proceeds from issuance of long-term debt		41,523		25,837		—		—		—		—		—			67,360
Repayment of long-term debt		(40,000	)	(26,000	)	(8,000	)	—		—		—		—			(74,000	)
Proceeds from issuance of common stock		—		—		—		181		—		—		(181	)		—
Net decrease in short-term borrowings from affiliate with original maturities of three months or less		(600	)	(5,400	)	—		—		—		—		400			(5,600	)
Other		(4,381	)	(151	)	(3	)	—		—		—		—			(4,535	)

Net cash provided by (used in) financing activities		(46,717	)	(11,887	)	(18,158	)	181		(3,112	)	(2,822	)	16,725			(65,790	)

Net increase in cash and equivalents		21,765		1,266		2,555		69		—		—		—			25,655
Cash and equivalents, beginning of period		9		4		1,713		—		—		—		—			1,726

Cash and equivalents, end of period	$	21,774		1,270		4,268		69		—		—		—		$	27,381

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating statement of cash flows (unaudited)

Nine months ended September 30, 2002

(in thousands)	HECO			HELCO		MECO		HECO Capital Trust I		HECO Capital Trust II		Elimination addition to (deduction from) cash flows		HECO consolidated
Cash flows from operating activities
Income before preferred stock dividends of HECO	$	70,629		11,988		14,455		3,112		2,822		(32,377	)	$	70,629
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities
Equity in earnings		(25,935	)	—		—		—		—		25,935			—
Common stock dividends received from subsidiaries		11,297		—		—		—		—		(11,297	)		—
Depreciation of property, plant and equipment		47,708		14,658		16,697		—		—		—			79,063
Other amortization		3,004		1,691		4,496		—		—		—			9,191
Deferred income taxes		5,752		128		(799	)	—		—		—			5,081
Tax credits, net		725		154		118		—		—		—			997
Allowance for equity funds used during construction		(2,680	)	(168	)	(129	)	—		—		—			(2,977	)
Changes in assets and liabilities
Decrease (increase) in accounts receivable		1,122		(744	)	212		—		—		(630	)		(40	)
Decrease (increase) in accrued unbilled revenues		(5,856	)	(127	)	351		—		—		—			(5,632	)
Decrease (increase) in fuel oil stock		(8,212	)	579		(1,497	)	—		—		—			(9,130	)
Increase in materials and supplies		(673	)	(351	)	(270	)	—		—		—			(1,294	)
Decrease (increase) in regulatory assets		(151	)	473		(1,708	)	—		—		—			(1,386	)
Increase (decrease) in accounts payable		6,172		(2,588	)	(2,631	)	—		—		—			953
Decrease in taxes accrued		(12,373	)	(1,494	)	(541	)	—		—		—			(14,408	)
Changes in other assets and liabilities		(14,674	)	(1,714	)	278		—		—		6,386			(9,724	)

Net cash provided by operating activities		75,855		22,485		29,032		3,112		2,822		(11,983	)		121,323

Cash flows from investing activities
Capital expenditures		(52,511	)	(16,717	)	(8,989	)	—		—		—			(78,217	)
Contribution in aid of construction		3,876		2,602		916		—		—		—			7,394
Repayments from affiliates		56		—		—		—		—		—			56
Other		(300	)	—		(13,000	)	—		—		13,300			—

Net cash used in investing activities		(48,879	)	(14,115	)	(21,073	)	—		—		13,300			(70,767	)

Cash flows from financing activities
Common stock dividends		(31,338	)	(4,670	)	(6,449	)	(93	)	(85	)	11,297			(31,338	)
Preferred stock dividends		(810	)	(400	)	(286	)	—		—		686			(810	)
Preferred securities distributions of trust subsidiaries		—		—		—		(3,019	)	(2,737	)	—			(5,756	)
Proceeds from issuance of long-term debt		11,691		—		—		—		—		—			11,691
Repayment of long-term debt		—		(5,000	)	—		—		—		—			(5,000	)
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		1,031		300		—		—		—		(13,300	)		(11,969	)
Other		(7,454	)	122		(7	)	—		—		—			(7,339	)

Net cash used in financing activities		(26,880	)	(9,648	)	(6,742	)	(3,112	)	(2,822	)	(1,317	)		(50,521	)

Net increase (decrease) in cash and equivalents		96		(1,278	)	1,217		—		—		—			35
Cash and equivalents, beginning of period		9		1,282		567		—		—		—			1,858

Cash and equivalents, end of period	$	105		4		1,784		—		—		—		$	1,893

Item 2.

Management’s discussion and analysis of financial condition and results of operations

The following discussion should be read in conjunction with the consolidated financial statements of HEI and HECO and accompanying notes.

RESULTS OF OPERATIONS

HEI Consolidated

(in thousands, except per share amounts)	Three months ended September 30,				% change		Primary reason(s) for significant change*
(in thousands, except per share amounts)	2003		2002		% change		Primary reason(s) for significant change*

Revenues	$	453,703	$	431,560	5	%	Increase for the electric utility and “other” segments, partly offset by a decrease for the bank segment

Operating income		68,235		71,738	(5	)	Decreases for the electric utility segment, partly offset by an increase for the bank and “other” segments

Net income		30,522		33,512	(9	)	Lower operating income, partly offset by lower other expenses (including interest and distributions on preferred securities), primarily due to lower interest rates and short-term borrowing balances

Basic earnings per common share	$	0.81	$	0.92	(12	)	See explanation for net income above and weighted-average number of common shares outstanding below

Weighted-average number of common shares outstanding		37,516		36,435	3		Issuances of shares under the DRIP and other plans

(in thousands, except per share amounts)	Nine months ended September 30,					% change	Primary reason(s) for significant change*
(in thousands, except per share amounts)	2003			2002		% change	Primary reason(s) for significant change*

Revenues	$	1,327,095		$	1,217,998	9	Increase for the electric utility and “other” segments, partly offset by a decrease for the bank segment

Operating income		188,776			206,968	(9)	Decreases for the electric utility and bank segments, slightly offset by an increase for the “other” segment

Income (loss) from:
Continuing operations	$	80,609		$	91,842	(12)	Lower operating income, partly offset by lower other expenses (including interest and distributions on preferred securities), primarily due to lower interest rates and lower borrowing balances

Discontinued operations		(3,870	)		—	NM	HEIPC writedown of investment in CEPALCO by $5 million and increase in reserve for future expenses of $1 million (primarily for general and administrative expenses during the longer than expected disposal period) in the second quarter of 2003

Net income	$	76,739		$	91,842	(16)

Basic earnings per common share–
Continuing operations	$	2.16		$	2.54	(15)
Discontinued operations		(0.10	)		—	NM

	$	2.06		$	2.54	(19)	See explanation for income above and
							weighted- average number of common shares outstanding below
Weighted-average number of common shares outstanding		37,205			36,150	3	Issuances of shares under the DRIP and other plans

*	Also see segment discussions which follow.

NM Not meaningful.

Economic conditions

Because its core businesses are providing local electric utility and banking services, HEI’s operating results are significantly influenced by the strength of Hawaii’s economy, which in turn is influenced by economic conditions in the mainland U.S. (particularly California) and Asia (particularly Japan) as a result of the impact of those conditions on tourism.

Hawaii’s economy has improved despite the weakness in tourism from Japan. For the first eight months of 2003, total visitor arrivals were down 1.3% from the same period last year, a combination of a weak international visitor market (down 11.5%) and a strong domestic market (up 3.2%). Total visitor days, however, were up 4.7% due to longer average lengths of stay in both domestic and international markets. Hotel occupancy also reached 83% in

August 2003, the state’s highest level since 1991. With these positive results, the state expects total visitor expenditures this year to top $10 billion for the first time.

Key non-tourism sectors, particularly construction, real estate and services, continue to be strong. Although interest rates have been fluctuating recently, they are still low historically and continue to spur activity in the construction and real estate industries. In the first seven months of 2003, the contracting tax base (a measure of construction activity subject to the general excise tax) increased 11.7% and the number of construction jobs grew 4.2% for the month of August 2003 compared with the same periods last year. Building permits, an indicator of future construction activity, also jumped 73.4% during the first seven months of 2003 over the same period in 2002. Real estate resales also continue to show strength in Hawaii. In the first nine months of 2003, single family dwelling and condominium resale volumes on Oahu were up 14.8% and 30.0%, respectively, while the median sales prices were up 12.6% and 16.1% respectively over the same period last year. In September 2003, the single family dwelling median price of $395,000 was the highest recorded on Oahu, and sales speed, at 25 days, was the fastest ever for Oahu homes. Other sectors showing notable growth include educational services and professional and business services, with job growth rates of 7.2% and 4.3%, respectively, in the second quarter of 2003 over the second quarter of 2002.

Hawaii’s improving economy is also reflected in other general economic statistics. Civilian employment and jobs continued their ascent, increasing by 4.0% and 2.1%, respectively, in the second quarter of 2003 over the same period last year. In the second quarter of 2003, the number of wage and salary jobs was at the highest level in Hawaii’s history. Hawaii’s unemployment rate, at 4.4%, also remained below the national average of 6.0% in August 2003. State tax revenues were up 7.4% for the second quarter of 2003 over the same period last year, and Hawaii bankruptcy filings decreased 6.4% during the same period. Hawaii has also experienced income growth, with personal income up 5.5% in the first quarter of 2003 compared with the same period last year.

Given these positive trends in key non-tourism sectors and overall economic indicators, the state expects Hawaii’s economy to grow moderately by 2.6% in 2003 excluding inflation. Future growth in Hawaii’s economy is expected to be tied primarily to the rate of expansion in the mainland U.S. and Japan economies, and remains vulnerable to uncertainties in the world geopolitical environment.

Dividends

HEI and its predecessor company, HECO, have paid dividends continuously since 1901. On October 28, 2003, HEI’s Board maintained the quarterly dividend of $0.62 per common share. The payout ratio based on net income for 2002 and the first nine months of 2003 was 76% and 90% (dividend payout ratio of 76% and 86% based on income from continuing operations), respectively. HEI management believes HEI should achieve and maintain a 65% payout ratio before it considers increasing the common stock dividend above its current level.

Pension and other postretirement benefits

Due to the sharp decline in U.S. equity markets from the third quarter of 2000 to the first quarter of 2003, the market value of assets held in trust to satisfy the obligations of the Company’s retirement benefit plans has decreased significantly. For 2002, 2001 and 2000, the realized and unrealized net losses on retirement benefit plan assets were $112 million, $96 million and $31 million, respectively. For the first nine months of 2003, the retirement benefit plan assets generated a total return slightly above 13% and higher than the 9% return assumption resulting in realized and unrealized net gains of approximately $80 million.

Depending on the 2003 investment experience and status of interest rates, the Company, like many sponsors of defined benefit pension plans, could be required to recognize an additional minimum liability as prescribed by SFAS No. 87, “Employers’ Accounting for Pensions” at December 31, 2003. The liability would largely be recorded as a reduction to stockholders’ equity through a non-cash charge to accumulated other comprehensive income (AOCI), and would not affect net income for 2003. The additional minimum liability would also result in the removal of the prepaid pension asset ($70 million as of December 31, 2002) from the Company’s balance sheet.

The amount of additional minimum liability and charge to AOCI, if any, to be recorded at December 31, 2003, could be material and will depend upon a number of factors, including the year-end discount rate assumption, asset returns experienced in 2003, any changes to actuarial assumptions or plan provisions, and contributions made by the Company to the plans during 2003. Although not required, HECO and ASB each made cash contributions of

$15 million for the ten months ended October 31, 2003 and HECO intends to make additional cash contributions of at least $5 million by December 31, 2003 to the retirement benefit plans. In addition, retirement benefits expense and cash funding requirements could increase in future years depending on the performance of the U.S. equity markets and trends in interest rates. Retirement benefit expenses based on net periodic pension and other postretirement benefit costs that are related to utility operations have been an allowable expense for rate-making, and higher retirement benefit expenses, along with other factors, may affect the need to request an electric rate increase.

Based on the market value of the retirement benefit plans’ assets as of September 30, 2003 of $730 million and the 1983 Group Annuity Mortality Table and assuming no further asset appreciation or depreciation through yearend, an expected long-term return on plan assets of 9% in future years, a range of 5.75% to 6.75% for the discount rate, and no further changes in assumptions or retirement benefit provisions, the Company’s, consolidated HECO’s and ASB’s AOCI balance (net of tax benefits) related to the minimum pension liability at December 31, 2003 and retirement benefits expense (net of tax benefits) for 2004 are projected to be as follows:

	Discount rate
($ in millions)	5.75%		6.75%
Consolidated HEI
AOCI balance (net of tax benefits)	$	90	$	43
Retirement benefits expense (net of tax benefits)		17		10

Consolidated HECO
AOCI balance (net of tax benefits)		88		43
Retirement benefits expense (net of tax benefits)		12		7

ASB
AOCI balance (net of tax benefits)		—		—
Retirement benefits expense (net of tax benefits)		3		2

The Company benchmarks its discount rate assumption to the Moody’s 20-year AA Corporate Bond Composite Index. Based on the forward curve as of October 31, 2003, the discount rate at December 31, 2003 is expected to be between 6.0% and 6.5%.

The Company’s, consolidated HECO’s and ASB’s retirement benefits expenses (net of tax benefits) are estimated to be $12 million, $8 million and $3 million, respectively, for 2003 compared to retirement benefits income (net of taxes) of the Company and consolidated HECO of $4 million and $6 million, respectively, and retirement benefits expense (net of tax benefits) of ASB of $1 million for 2002.

If the Company and consolidated HECO are required to record substantially greater charges to AOCI in the future than the charges that might be required under the assumptions described above, the Company’s and consolidated HECO’s financial ratios may deteriorate, which could result in security ratings downgrades and difficulty (or greater expense) in obtaining future financing. In addition, there may be possible financial covenant violations (although there are no advances currently outstanding under any credit facility subject to financial covenants) as certain bank lines of credit of the Company and HECO require that HECO maintain a minimum ratio of consolidated common equity to consolidated capitalization of 35% and that the Company and HECO maintain a consolidated net worth, exclusive of intangible assets, of at least $850 million and $825 million, respectively.

Insurance

After completing a three year policy period, directors and officers liability insurance will be renewed in February 2004 and management expects significant premium increases in 2004 based on current market conditions.

Following is a general discussion of the results of operations by business segment.

Electric utility

(dollars in thousands, except per barrel amounts)	Three months ended September 30,				% change		Primary reason(s) for significant change
(dollars in thousands, except per barrel amounts)	2003		2002		% change		Primary reason(s) for significant change
Revenues	$	359,250	$	333,636	8	%	Higher fuel oil and purchased energy fuel costs ($18 million), the effects of which are generally passed on to customers, and 2.7% higher KWH sales ($10 million), partly offset by lower amounts of integrated resource planning costs recovered through surcharges

Expenses

Fuel oil		101,296		85,311	19		Higher fuel oil costs and more KWHs generated

Purchased power		92,543		87,123	6		Higher fuel costs and more KWHs purchased

Other		118,775		107,613	10		Higher other operation and maintenance expenses (including pension and other postretirement benefits), depreciation and taxes, other than income taxes, and a $1.6 million accrual for a potential environmental liability

Operating income		46,636		53,589	(13	)	Higher KWH sales, more than offset by higher other operation and maintenance expenses, depreciation, taxes, other than income taxes, and a $1.6 million accrual for a potential environmental liability

Net income		20,360		25,610	(20	)	Lower operating income, partly offset by lower income taxes

Kilowatthour sales (millions)		2,583		2,515	3

Cooling degree days (Oahu)		1,639		1,539	6

Fuel oil cost per barrel	$	35.62	$	30.68	16

(dollars in thousands, except per barrel amounts)	Nine months ended September 30,				% change		Primary reason(s) for significant change
(dollars in thousands, except per barrel amounts)	2003		2002		% change		Primary reason(s) for significant change
Revenues	$	1,042,691	$	919,643	13	%	Higher fuel oil and purchased energy fuel costs ($106 million), the effects of which are generally passed on to customers, and 2.1% higher KWH sales ($22 million), partly offset by lower amounts of integrated resource planning costs recovered through surcharges
Expenses
Fuel oil		294,303		218,901	34		Higher fuel oil costs and more KWHs generated

Purchased power		273,161		240,744	13		Higher fuel costs, more KWHs purchased and higher capacity payments

Other		345,031		309,852	11		Higher other operation and maintenance expenses (including pension and other postretirement benefits), depreciation and taxes, other than income taxes, and a $1.6 million accrual for a potential environmental penalty

Operating income		130,196		150,146	(13	)	Higher KWH sales, more than offset by higher other operation and maintenance expenses, depreciation and taxes, other than income taxes

Net income		56,572		69,819	(19	)	Lower operating income, partly offset by lower income taxes
Kilowatthour sales (millions)		7,269		7,117	2

Cooling degree days (Oahu)		3,750		3,611	4

Fuel oil cost per barrel	$	36.75	$	27.52	34

Kilowatthour (KWH) sales in the third quarter and first nine months of 2003 increased 2.7% and 2.1%, respectively, from the same periods in 2002, primarily due to slightly warmer weather, increased commercial usage, and increased residential usage due in part to the strong real estate market. KWH sales increases for the first nine months of 2003 over the first nine months of 2002 for HECO, HELCO, and MECO were 84 million KWHs, 35 million KWHs and 33 million KWHs, respectively. While all the electric utilities showed sales growth due in large part to strength in non-tourism sectors of the economy, KWH sales growth, particularly at HECO, was tempered by the impact on tourism of concerns over the Japanese economy, the war in Iraq, terrorism and SARS. Cooling degree days were 4% higher in the first nine months of 2003 compared with the first nine months of 2002.

Electric utility operating income for the third quarter of 2003 decreased 13% from the third quarter of 2002, primarily due to higher other operation, maintenance and depreciation expenses and a $1.6 million accrual for a

potential environmental liability (see “Environmental regulation — Maalaea Units 12 and 13 notice and finding of violation” in note (4) in HECO’s “Notes to consolidated financial statements”), which more than offset the impact of higher KWH sales (net of taxes, other than income taxes). Other operation expense increased 11% primarily due to higher pension and other postretirement benefits expense. Pension and other postretirement benefit expenses for the electric utilities increased $5.5 million over the same period in 2002 ($3.4 million expense in the third quarter of 2003 versus a $2.1 million credit in the third quarter of 2002), partly due to revised assumptions (decreasing the discount rate 50 basis points to 6.75% and the long-term rate of return on assets 100 basis points to 9.0% as of December 31, 2002 compared to December 31, 2001) and the effect of the stock market decline on the performance of the assets held in trust to satisfy the obligations of the retirement benefit plans. While not significant for the third quarter of 2003, the Company expects to continue to incur additional costs for security at its facilities and to comply with the requirements of the Sarbanes-Oxley Act of 2002. Also, internal efforts to improve the security of the Company’s information technology (IT) systems is on-going, but are not currently expected to result in significantly increased costs for 2003. Maintenance expense increased 15% primarily due to higher production maintenance and vegetation management expenses. Higher depreciation expense was attributable to plant placed in service in 2002.

Electric utility operating income for the first nine months of 2003 decreased 13% from the first nine months of 2002, primarily due to higher other operation, maintenance and depreciation expenses and the $1.6 million accrual for a potential environmental liability, which more than offset the impact of higher KWH sales (net of taxes, other than income taxes). Other operation expense increased 20% primarily due to higher retirement benefits expense and environmental expenses (including a $1.5 million non-recurring adjustment of emission fees). Pension and other postretirement benefit expenses for the electric utilities increased $18.2 million over the same period in 2002 ($10.4 million expense in the first nine months of 2003 versus a $7.8 million credit in the first nine months of 2002), partly due to revised assumptions and the effect of the stock market decline on the performance of the assets held in trust to satisfy the obligations of the retirement benefit plans. Maintenance expense increased 4% primarily due to higher production maintenance and vegetation management expenses. Higher depreciation expense was attributable to plant placed in service in 2002.

Competition

The electric utility industry in Hawaii has become increasingly competitive. Although several IPPs have established power purchase agreements with the electric utilities, 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. However, customer self-generation, with or without cogeneration, is a continuing competitive factor.

Recent developments involving distributed generation. Historically, HECO and its subsidiaries have been able to compete by offering customers economic alternatives that, among other things, employ energy efficient electrotechnologies such as the heat pump water heater. However, the number of customer self-generation projects that are being proposed or installed in Hawaii, particularly those involving combined heat and power (CHP) systems, is growing. CHP systems are a form of distributed generation (DG), and produce electricity and thermal energy from gas, propane or diesel-fired engines. In Hawaii, the thermal energy generally is used to heat water and, through an absorption chiller, drive an air conditioning system. The electric energy generated by these systems is usually lower in output than the customer’s load, which results in continued connection to the utility grid to make up the difference in electricity demand and to provide back up electricity.

The electric utilities have initiated several demonstration projects and other activities, including a small customer-owned CHP demonstration project on Maui, to provide on-going evaluation of DG. The electric utilities also have made a limited number of proposals to customers to install and operate utility-owned CHP systems at the customers’ sites. Incremental generation from such customer-sited CHP systems, and other DG, is expected to complement traditional central station power, as part of the electric utilities’ plans to serve their forecast load growth. The offering of CHP systems would be subject to PUC review and approval. To facilitate such an offering, the electric utilities signed a teaming agreement, in early 2003, with a manufacturer of packaged CHP systems, but the teaming agreement does not commit the electric utilities to make any CHP system purchases.

In July 2003, three vendors of DG/CHP equipment and services proposed, in an informal complaint to the PUC, that the PUC open a proceeding to investigate the electric utilities’ provision of CHP services and the teaming agreement with another vendor, and to issue rules or orders to govern the terms and conditions under which the electric utilities will be permitted to engage in utility-owned DG at individual customers sites. On August 5, 2003, the electric utilities responded to the informal complaint, and to information requests from the PUC on the CHP demonstration project and teaming agreement.

In October 2003, the electric utilities filed an application for approval of a CHP tariff, under which they would provide CHP services to eligible commercial customers. Under the tariff, the electric utilities would own, operate and maintain customer-sited, packaged CHP systems (and certain ancillary equipment used to convert waste heat to chilled or heated water) pursuant to a standard form of contract with the customer. Pending approval of a CHP tariff, the electric utilities plan to request approval for individual CHP projects.

On October 21, 2003, the PUC opened an investigative docket to determine the potential benefits and impact of DG on Hawaii’s electric distribution systems and markets and to develop polices and a framework for DG projects deployed in Hawaii. The PUC intends to address issues related to interconnection matters, ownership and operation of DG projects, impacts of such projects on Hawaii’s electrical distribution systems and markets, defining the role of regulated electric utilities and the PUC in the deployment of DG, identifying rate design and cost allocation issues associated with DG deployment and developing revisions to the integrated resource planning process, if necessary. The PUC indicated it also plans to address issues raised in the informal complaint filed by three vendors of DG/CHP equipment.

1996 Competition docket and related proceedings. In 1996, the PUC instituted 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. Several of the parties submitted final statements of position to the PUC in 1998. HECO’s position in the proceeding was that retail competition is not feasible in Hawaii, but that some of the benefits of competition could be achieved through competitive bidding for new generation, performance-based rate-making (PBR) and innovative pricing provisions. The other parties to the proceeding advanced numerous other proposals.

In May 1999, the PUC approved HECO’s standard form contract for customer retention that allows HECO to provide a rate option for customers who would otherwise reduce their energy use from HECO’s system by using energy from a nonutility generator. Based on HECO’s current rates, the standard form contract provides a 2.77% and an 11.27% discount on base energy rates for qualifying “Large Power” and “General Service Demand” customers, respectively. In March 2000, the PUC approved a similar standard form contract for HELCO which, based on HELCO’s current rates, provides a 10.00% discount on base energy rates for qualifying “Large Power” and “General Service Demand” customers.

In December 1999, HECO, HELCO and MECO filed an application with the PUC seeking permission to implement PBR in future rate cases. In early 2001, the PUC dismissed the PBR proposal without prejudice, indicating it declined at that time to change its current cost of service/rate of return methodology for determining electric utility rates.

In January 2000, the PUC submitted to the legislature a status report on its investigation of competition. The report stated that competitive bidding for new power supplies (i.e., wholesale generation competition) is a logical first step to encourage competition in Hawaii’s electric industry and that the PUC plans to proceed with an examination of the feasibility of competitive bidding and to review specific policies to encourage renewable energy resources in the power generation mix. The report stated that “further steps” by the PUC “will involve the development of specific policies to encourage wholesale competition and the continuing examination of other areas suitable for the development of competition.”

On October 21, 2003, the PUC closed the competition proceeding instituted in 1996. The PUC found that developments in other states indicate that, at best, implementation of retail access would be premature, and determined that no action will be taken to implement retail electric competition in Hawaii at this time. The PUC concluded that projections of any potential benefits of restructuring Hawaii’s electric industry are too speculative and that it has not been sufficiently demonstrated that all consumers in Hawaii would continue to receive adequate, safe, reliable, and efficient energy services at fair and reasonable prices under a restructured market at this time. The PUC

indicated it will take a cautious approach to restructuring and will continue to monitor restructuring experiences in other states and at the federal level before proceeding with any major restructuring in Hawaii. The PUC determined that it was in the public interest to work within the current regulatory system to strive to improve efficiency within the electric industry, and opened investigative dockets on competitive bidding and DG to move toward a more competitive electric industry environment under cost-based regulation. The stated purpose of the competition bidding investigation is to evaluate competitive bidding as a mechanism for acquiring or building new generating capacity in Hawaii. The PUC has made the electric utilities in Hawaii and the Consumer Advocate parties to the new proceedings, and invited interested energy service providers and other business, environmental, cultural and community groups to file motions to intervene or participate in the dockets. The PUC stated it would consider related filings on a case-by-case basis pending completion of the docket. Management cannot predict the ultimate outcome of these proceedings.

Regulation of electric utility rates

The PUC has broad discretion in its regulation of the rates charged by HEI’s electric utility subsidiaries and in other matters. Any adverse D&O by the PUC concerning the level or method of determining electric utility rates, the authorized returns on equity or other matters, or any prolonged delay in rendering a D&O in a rate or other proceeding, could have a material adverse effect on the Company’s results of operations and financial condition. Upon a showing of probable entitlement, the PUC is required to issue an interim D&O in a rate case within 10 months from the date of filing a completed application if the evidentiary hearing is completed (subject to extension for 30 days if the evidentiary hearing is not completed). There is no time limit for rendering a final D&O. Interim rate increases are subject to refund with interest, pending the final outcome of the case.

At September 30, 2003, HECO and its subsidiaries had recognized $17 million of revenues under interim orders which allowed them to recover certain integrated resource planning costs they incurred since 1995, which revenues are subject to refund, with interest, to the extent they exceed the amounts that are allowed in final orders. The Consumer Advocate has objected to the recovery of $2.4 million (before interest) of the $10 million of incremental costs incurred during 1995 through 2001.

Management cannot predict with certainty when D&Os in future rate cases will be rendered or the amount of any interim or final rate increase that may be granted. There are no rate cases pending at this time. HECO, however, has committed to file a rate increase application (see “Other regulatory matters, Demand-side management programs – agreements with the Consumer Advocate”).

The rate schedules of the electric utility subsidiaries include energy cost adjustment clauses (ECAC) under which electric rates charged to customers are automatically adjusted for changes in the weighted-average cost of fuel oil and certain energy components of purchased power, and the mix of energy sources used in company-generated power and purchased power. Purchased power capacity payments are included in the determination of base rates and are not a part of the ECAC. The company generation component in the ECAC includes an efficiency factor that is determined and fixed in a rate case proceeding. Expenses that are incurred by the utility because its fuel efficiency is worse than the fixed efficiency level cannot be passed on to customers. If the utility’s efficiency is better than the fixed efficiency level, however, it keeps the savings associated with the higher efficiency. In 1997 PUC decisions approving the electric utilities’ fuel supply contracts, the PUC noted that, in light of the length of the fuel supply contracts and the relative stability of fuel prices, the need for continued use of energy cost adjustment clauses would be the subject of investigation in a generic docket or in a future rate case. The electric utility subsidiaries believe that the energy cost adjustment clauses continue to be necessary. These clauses were continued in the most recent HELCO and MECO rate cases (final D&O’s issued in February 2001 and April 1999, respectively).

Consultants periodically conduct depreciation studies for the electric utilities to determine whether the existing approved rates and methods used to calculate depreciation accruals are appropriate for the production, transmission, distribution and general plant accounts. If it is determined that the existing rates and methods are no longer appropriate, changes to those rates are recommended as part of the study. In October 2002, HECO filed an application with the PUC for approval to change its depreciation rates and to change to vintage amortization accounting for selected plant accounts, which changes would have amounted to an approximate $4.2 million, or 6.3%, increase in depreciation expense based on a study of depreciation expense for 2000. In its application, HECO

requested that the effective date of the proposed changes coincide with the effective date of the rates established in HECO’s next rate case proceeding so that HECO’s financial results would not be negatively impacted by the depreciation rates and method ultimately approved by the PUC. In July 2003, the Consumer Advocate submitted its direct testimony and recommended depreciation expense approximately $31.8 million, or 45%, less than HECO’s requested $70.8 million in annual depreciation expense. HECO’s rebuttal testimony was submitted in August 2003.

Most recent rate requests

HEI’s electric utility subsidiaries initiate PUC proceedings from time to time to request electric rate increases to cover rising operating costs (e.g., the cost of purchased power) and the cost of plant and equipment, including the cost of new capital projects to maintain and improve service reliability. As of November 1, 2003, 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). For 2002, the actual ROACEs (calculated under the rate-making method and reported semiannually to the PUC) for HECO, HELCO and MECO were 11.33%, 7.52% and 10.30%, respectively. For the twelve months ended June 30, 2003, the actual ROACEs for HECO, HELCO and MECO were 9.79%, 7.02% and 10.42%, respectively.

As of November 1, 2003, the return on average rate base (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). For 2002, the actual RORs (calculated under the rate-making method and reported semiannually to the PUC) for HECO, HELCO and MECO were 8.94%, 9.15% and 8.83%, respectively. MECO’s and HELCO’s RORs were higher than 8.83% and 9.14%, respectively, for 2002. Consequently, an adjustment was made to their shareholder incentives under their demand-side management (DSM) programs in accordance with their agreements for the temporary continuation of the programs. See “Other regulatory matters, Demand-side management programs – agreements with the Consumer Advocate.” For the twelve months ended June 30, 2003, the actual RORs for HECO, HELCO and MECO were 8.19%, 9.09% and 8.94%, respectively.

Hawaiian Electric Company, Inc. HECO has not initiated a rate case for several years, but in 2001 it committed to initiate a rate case within three years, using a 2003 or 2004 test year, as part of the agreements described below. HECO has requested that the time for initiating the rate case be extended by 12 months, and the PUC has approved the request, with the result that the rate case is to be initiated approximately 12 months later, using a 2005 test year. See “Other regulatory matters, Demand-side management programs – agreements with the Consumer Advocate.”

Hawaii Electric Light Company, Inc. In early 2001, HELCO received a final D&O from the PUC authorizing an $8.4 million, or 4.9% increase in annual revenues, effective February 15, 2001 and based on an 11.50% ROACE. The D&O included in rate base $7.6 million for pre-air permit facilities needed for the delayed Keahole power plant expansion project that the PUC had also found to be used or useful to support the existing generating units at Keahole.

On June 1, 2001, the PUC issued an order approving a new standby service rate schedule rider for HELCO. The standby service rider issue had been bifurcated from the rest of the rate case. The rider provides the rates, terms and conditions for obtaining backup and supplemental electric power from the utility when a customer obtains all or part of its electric power from sources other than HELCO.

The timing of a future HELCO rate increase request to recover costs relating to the delayed Keahole power plant expansion project, i.e., adding two combustion turbines (CT-4 and CT-5) at Keahole, including the remaining cost of pre-air permit facilities, will depend on future circumstances. See “HELCO power situation” in note (4) of HECO’s “Notes to Consolidated Financial Statements.”

Other regulatory matters

Demand-side management programs—lost margins and shareholder incentives. HECO, HELCO and MECO’s energy efficiency DSM programs, currently approved by the PUC, provide for the recovery of lost margins and the earning of shareholder incentives.

Lost margins are accrued and collected prospectively based on the programs’ forecast levels of participation, and are subject to two adjustments based on (1) the actual level of participation and (2) the results of impact evaluation reports. The difference between the adjusted lost margins and the previously collected lost margins are subject to refund or recovery, with any over or under collection accruing interest at HECO, HELCO, or MECO’s authorized rate of return on rate base. HECO, HELCO and MECO plan to file the impact evaluation report for the 2000-2002 period with the PUC in the fourth quarter of 2004 and adjust the lost margin recovery as required. Past adjustments required for lost margins have not had a material effect on HECO, HELCO or MECO’s financial statements.

Shareholder incentives are accrued currently and collected retrospectively based on the programs’ actual levels of participation for the prior year. Beginning in 2001, shareholder incentives collected became subject to retroactive adjustment based on the results of impact evaluation reports, similar to the adjustment process for lost margins.

Demand-side management programs – agreements with the Consumer Advocate. In October 2001, HECO and the Consumer Advocate finalized agreements, subject to PUC approval, under which HECO’s three commercial and industrial DSM programs and two residential DSM programs would be continued until HECO’s next rate case, which, under the agreements, HECO committed to file using a 2003 or 2004 test year and following the PUC’s rules for determining the test year. The PUC rules require that an application be filed between July and December 2003 in order to use a 2004 test year. The agreements for the temporary continuation of HECO’s existing DSM programs were in lieu of HECO continuing to seek approval of new 5-year DSM programs. Any DSM programs to be in place after HECO’s next rate case will be determined as part of the case. Under the agreements, HECO will 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 found by the PUC to be reasonable in the most recent rate case for HECO). HECO also agreed it will not pursue the continuation of lost margins recovery and shareholder incentives through a surcharge mechanism in future rate cases. Consistent with the HECO agreements, in October 2001, HELCO and MECO reached agreements with the Consumer Advocate 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 (1) the agreements regarding the temporary continuation of HECO’s five existing DSM programs until HECO’s next rate case and (2) 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. In 2002, MECO’s revenues from shareholder incentives were $0.7 million lower than the amount that would have been recorded if MECO had not agreed to cap such incentives when its authorized return on rate base was exceeded. Also in 2002, HELCO slightly exceeded its authorized return on rate base resulting in a reduction to shareholders incentives of approximately $31,000, which HELCO recorded in January 2003. In 2002, HECO did not exceed its authorized return on rate base.

With respect to HECO’s agreement with the Consumer Advocate regarding HECO’s three commercial and industrial DSM programs, the parties agreed on August 7, 2003, subject to PUC approval, to a delay in the filing of HECO’s next rate case by approximately 12 months, with the result that the rate case would be filed using a 2005 test year. A similar agreement with respect to its two residential DSM programs was reached on August 12, 2003, subject to PUC approval. The other components of the existing agreements, as approved by the PUC, would be continued under the new agreements. On August 26, 2003, the PUC issued orders approving the new agreements.

Collective bargaining agreements

See “Collective bargaining agreements” in note (4) in HECO’s “Notes to consolidated financial statements.”

Legislation

Congress and the Hawaii legislature periodically consider legislation that could have positive or negative effects on the utilities and their customers. For example, although it is currently stalled in a House-Senate conference committee, comprehensive energy legislation is still before Congress that could increase the domestic supply of oil as well as increase support for energy conservation programs and mandate the use of renewables by utilities. The 2003

Hawaii legislature considered measures that would undertake a comprehensive audit of Hawaii’s electric utility regulatory policies, energy policies and support for reducing Hawaii’s dependence on imported petroleum for electrical generation, and a measure to remove the cap on the amount of net energy metering the utilities would be required to make available to eligible customers. These measures were not enacted into law. The legislature did, however, pass a more restricted bill calling for a management audit of the PUC and Consumer Advocate. Also, the legislature passed a law, which took effect on July 1, 2003, that required employers who have at least 100 employees to allow their employees to use up to 10 days of their compensated sick leave per year to care for a sick family member. On June 26, 2003, the Governor signed into law the Hawaii State tax credit for renewable energy, which extends the existing tax credit of 35% of the cost of residential solar water heating (up to $1,750) until at least 2008.

In its 2001 session, the Hawaii legislature passed a law establishing “renewable portfolio standard” goals for electric utilities of 7% by December 31, 2003, 8% by December 31, 2005 and 9% by December 31, 2010. HECO, HELCO and MECO are permitted to aggregate their renewable portfolios in order to achieve these goals. Any electric utility whose percentage of sales of electricity represented by renewable energy does not meet these goals will have to report to the PUC and provide an explanation for not meeting the renewables portfolio standard. The PUC could then grant a waiver from the standard or an extension for meeting the standard. The PUC may also provide incentives to encourage electric utilities to exceed the standards or meet the standards earlier, or both, but as yet no such incentives have been proposed. The law also requires that electric utilities offer net energy metering to solar, wind turbine, biomass or hydroelectric generating systems (or hybrid systems) with a capacity up to 10 kilowatts (i.e., a customer-generator may be a net user or supplier of energy and will make payments to or receive credits from the electric utility accordingly).

The electric utilities currently support renewable sources in various ways, including their solar water heating and heat pump programs and their purchased power contracts with nonutility generators using renewable sources (e.g., refuse-fired, geothermal, hydroelectric and wind turbine generating systems). The electric utilities continue to initiate and support many renewable energy research and development projects to help develop these technologies (e.g., photovoltaic projects). They are also conducting integrated resource planning to evaluate the use of more renewables and, in December 2002, HECO formed a subsidiary, Renewable Hawaii, Inc. (RHI), to invest in renewable energy projects. In May 2003, RHI solicited competitive proposals for investment opportunities in projects (1 MW or larger) to supply renewable energy on the island of Oahu. RHI is currently reviewing proposals received. In September 2003, RHI issued a similar request for renewable project proposals (due December 4, 2003) for the islands of Maui, Molokai and Lanai. RHI is seeking to take a passive, minority interest in such projects to help stimulate the addition of cost-effective, commercially viable renewable energy generation in the state of Hawaii. About 6.8% of electricity sales for 2002 were from renewable resources (as defined under the renewable portfolio standard law). Despite their efforts, the electric utilities believe it may be difficult to increase this percentage to the percentages targeted in the 2001 Hawaii legislation, particularly if sales of electricity increase in future years as projected. Thus, at this time, management cannot predict the impact of this law or of other proposed congressional and Hawaii legislation on the utilities or their customers.

Bank

(in thousands)	Three months ended September 30,						% change		Primary reason(s) for significant change
(in thousands)	2003			2002			% change		Primary reason(s) for significant change
Revenues	$	93,770		$	99,722		(6	)	Lower interest income (primarily due to lower loan and mortgage-related securities weighted-average yields, partly offset by the impact of a higher average balance of loans), partly offset by higher fee income and gain on sale of securities

Operating income		25,116			24,566		2		Lower net interest income and higher general and administrative expenses (primarily compensation and employee benefits, including pension), more than offset by a lower provision for loan losses and higher fee income and gain on sale of securities

Net income		15,275			14,652		4		Higher operating income and lower income taxes

Interest rate spread		3.01	%		3.28	%			98 basis points decrease in the weighted-average yield on interest-earning assets, partly offset by a 71 basis points decrease in the weighted-average rate on interest-bearing liabilities

(in thousands)	Nine months ended September 30,						% change		Primary reason(s) for significant change
(in thousands)	2003			2002			% change		Primary reason(s) for significant change
Revenues	$	281,575		$	300,633		(6	)	Lower interest income (primarily due to lower loan and mortgage-related securities weighted-average yields, partly offset by the impact of higher average balances), partly offset by higher fee income and gain on sale of securities

Operating income		69,903			71,106		(2	)	Lower net interest income and higher general and administrative expenses (primarily compensation and employee benefits, including pension), partly offset by a lower provision for loan losses and higher fee income and gain on sale of securities

Net income		42,277			42,815		(1	)	Lower operating income

Interest rate spread		3.06	%		3.28	%			86 basis points decrease in the weighted-average yield on interest-earning assets, partly offset by a 64 basis points decrease in the weighted-average rate on interest-bearing liabilities

Earnings of ASB depend primarily on net interest income, which is the difference between interest earned on interest-earning assets and interest paid on interest-bearing liabilities. 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. At September 30, 2003, ASB’s loan portfolio mix consisted of 78% residential loans, 9% business loans, 7% consumer loans and 6% commercial real estate loans. At December 31, 2002, ASB’s loan portfolio mix consisted of 78% residential loans, 8% business loans, 8% consumer loans and 6% commercial real estate loans. ASB’s mortgage-related securities portfolio consists primarily of shorter duration assets and is affected by market interest rates and demand. High prepayments have adversely impacted the yield of the mortgage-related securities portfolio. Deposits continue to be the largest source of funds 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. At September 30, 2003, ASB’s costing liabilities consisted of 47% core deposits, 21% term certificates and 32% FHLB advances and other borrowings. At December 31, 2002, ASB’s costing liabilities consisted of 45% core deposits, 22% term certificates and 33% FHLB advances and other borrowings. Other factors primarily affecting ASB’s operating results include gains or losses on sales of securities available for sale, fee income, provision for loan losses, changes in the value of mortgage servicing rights and expenses from operations.

Low interest rates and high mortgage refinancing volume have put pressure on ASB’s interest rate spread as the loan and mortgage-related securities portfolios reprice upon refinancing at lower interest rates and premiums on mortgage-related securities must be amortized more rapidly, while at the same time deposit rates are already at low levels that are difficult to reduce further without loss of deposits. Although long-term interest rates have started to increase from their low in June 2003, ASB does not foresee any significant impact to the yields on its loans and mortgage-related securities for approximately 60 to 90 days due to lags inherent in the processing and closing of mortgage loan applications. Although higher long-term interest rates could reduce the market value of mortgage-related securities and reduce stockholder’s equity through a balance sheet charge to AOCI, this reduction in market value of 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. At June 30 and September 30, 2003, the unrealized gain, net of taxes, on available-for-sale mortgage-related securities (including securities pledged for repurchase agreements) in AOCI was $23 million and $7 million, respectively. See “Item 3. 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 interest-earning assets and interest-bearing liabilities for the periods indicated.

	Three months ended September 30,							Nine months ended September 30,
($ in thousands)	2003		2002		Change			2003		2002		Change
Loans
Average balances (1)	$	3,127,709	$	2,834,512	$	293,197		$	3,059,889	$	2,818,592	$	241,297
Interest income (2)		49,657		50,210		(553	)		150,555		152,300		(1,745	)
Weighted-average yield (%)		6.35		7.09		(0.74	)		6.56		7.20		(0.64	)

Mortgage-related securities
Average balances	$	2,707,368	$	2,751,435	$	(44,067	)	$	2,712,423	$	2,626,965	$	85,458
Interest income		24,876		35,503		(10,627	)		80,176		103,634		(23,458	)
Weighted-average yield (%)		3.68		5.16		(1.48	)		3.94		5.26		(1.32	)

Investments (3)
Average balances	$	182,843	$	223,370	$	(40,527	)	$	195,701	$	258,602	$	(62,901	)
Interest and dividend income		1,428		1,880		(452	)		4,736		5,979		(1,243	)
Weighted-average yield (%)		3.09		3.33		(0.24	)		3.23		3.08		0.15

Total interest-earning assets
Average balances	$	6,017,920	$	5,809,317	$	208,603		$	5,968,013	$	5,704,159	$	263,854
Interest and dividend income		75,961		87,593		(11,632	)		235,467		261,913		(26,446	)
Weighted-average yield (%)		5.05		6.03		(0.98	)		5.26		6.12		(0.86	)

Deposits
Average balances	$	3,919,376	$	3,743,883	$	175,493		$	3,855,770	$	3,699,915	$	155,855
Interest expense		13,099		17,833		(4,734	)		41,182		57,331		(16,149	)
Weighted-average rate (%)		1.33		1.89		(0.56	)		1.43		2.07		(0.64	)

Borrowings
Average balances	$	1,885,260	$	1,793,534	$	91,726		$	1,862,144	$	1,758,328	$	103,816
Interest expense		16,736		20,588		(3,852	)		53,126		58,583		(5,457	)
Weighted-average rate (%)		3.51		4.54		(1.03	)		3.80		4.45		(0.65	)

Total interest-bearing liabilities
Average balances	$	5,804,636	$	5,537,417	$	267,219		$	5,717,914	$	5,458,243	$	259,671
Interest expense		29,835		38,421		(8,586	)		94,308		115,914		(21,606	)
Weighted-average rate (%)		2.04		2.75		(0.71	)		2.20		2.84		(0.64	)

Net balance, net interest income and interest rate spread
Net balance	$	213,284	$	271,900	$	(58,616	)	$	250,099	$	245,916	$	4,183
Net interest income		46,126		49,172		(3,046	)		141,159		145,999		(4,840	)
Interest rate spread (%)		3.01		3.28		(0.27	)		3.06		3.28		(0.22	)

(1)	Includes nonaccrual loans.

(2)

Includes interest accrued prior to suspension of interest accrual on nonaccrual loans and loan fees of $2.3 million and $0.9 million for the three months ended September 30, 2003 and 2002, respectively, and $6.1 million and $2.7 million for the nine months ended September 30, 2003 and 2002, respectively.

(3)	Includes stock in the FHLB of Seattle.

Three months ended September 30, 2003

Net interest income before provision for losses for the third quarter of 2003 decreased by $3.0 million, or 6.2%, from the same period in 2002. Net interest spread decreased from 3.28% for the third quarter of 2002 to 3.01% for the third quarter of 2003 as ASB’s yield on interest-earning assets decreased faster than the cost of interest-bearing liabilities. As interest rates decreased significantly in the past year, prepayments on mortgage-related securities increased, resulting in increased premium amortization and lower yields on those securities and replacement mortgage-related securities. The 10.3% increase in the average loan portfolio balance was due primarily to an increase in the residential loan portfolio as the strong Hawaii real estate market and low interest rates have resulted in increased affordability of housing for consumers and higher loan refinancings. The 4.7% increase in average deposit balances was due to an increase in core deposit balances. Other borrowings increased by 5.1% to fund the increase in the residential loan portfolio and to fund ASB’s securities purchases.

The provision for loan losses for the third quarter of 2003 was $0.9 million lower than the third quarter of 2002 as delinquencies have been below historical norms.

Other income for the third quarter of 2003 increased by $5.7 million, or 46.8%, over the same period in 2002. Fee income on loans serviced for others, net, for the third quarter of 2003 increased by $2.8 million compared to the same period in 2002 as the bank recorded a $1.9 million reversal of its mortgage servicing rights valuation allowance due to slower forecasted prepayments on its servicing portfolio. For the third quarter of 2002, the bank recorded a $1.3 million writedown of its mortgage servicing rights. Gains on sales of mortgage-related securities for the third quarter of 2003 increased by $2.6 million compared to the same period in 2002 as ASB sold securities to manage the prepayment risk in its mortgage-related securities portfolio.

General and administrative expenses for the third quarter of 2003 increased by $3.0 million, or 8.5%, over the same period in 2002. Compensation and employee benefits for the third quarter of 2003 was $2.2 million higher than the same period in 2002 primarily due to the increased staffing levels that have resulted from implementation of its strategic transformation from a retail thrift to a full-service community bank and higher pension costs.

Nine months ended September 30, 2003

Net interest income before provision for losses for the first nine months of 2003 decreased by $4.8 million, or 3.3%, from the same period in 2002. Net interest spread decreased from 3.28% for the first nine months of 2002 to 3.06% for the first nine months of 2003 as ASB’s yield on interest-earning assets decreased faster than the cost of interest-bearing liabilities. As interest rates decreased significantly in the past year, prepayments on mortgage-related securities increased, resulting in increased premium amortization and lower yields on those securities and replacement mortgage-related securities. The 8.6% increase in the average loan portfolio balance was due primarily to an increase in the residential loan portfolio. The 3.3% increase in the average mortgage-related securities portfolio was due to the reinvestment of excess cash into mortgage-related securities. The 4.2% increase in average deposit balances was due to an increase in core deposit balances. Other borrowings increased by 5.9% to fund the increase in the residential loan portfolio and to fund ASB’s securities purchases.

The provision for loan losses for the first nine months of 2003 was $5.2 million lower than the first nine months of 2002 as delinquencies have been below historical norms. As of September 30, 2003, ASB’s allowance for loan losses was 1.48% of average loans outstanding, compared to 1.62% as of September 30, 2002. The following table presents the changes in the allowance for loan losses for the periods indicated.

Nine months ended September 30	2003			2002
(in thousands)
Allowance for loan losses, January 1	$	45,435		$	42,224
Provision for loan losses		2,775			8,000
Net charge-offs		(3,005	)		(4,442	)

Allowance for loan losses, September 30	$	45,205		$	45,782

Other income for the first nine months of 2003 increased by $7.4 million, or 19.1%, over the same period in 2002. Fee income from other financial services increased by $2.6 million for the first nine months of 2003 compared to the same period in 2002 due to higher fee income from debit and ATM cards resulting from ASB’s expansion of its debit

card base and its introduction of new ATM services. Gains on sales of mortgage-related securities for the first nine months of 2003 increased by $4.7 million compared to the same period in 2002 as ASB sold securities to manage the prepayment risk in its mortgage-related securities portfolio.

General and administrative expenses for the first nine months of 2003 increased by $9.0 million, or 8.5%, over the same period in 2002. Compensation and employee benefits for the first nine months of 2003 was $5.7 million higher than the same period in 2002 primarily due to the increased staffing levels as ASB continued implementation of its strategic transformation from a retail thrift to a full-service community bank and higher pension cost.

ASB continues to manage the volatility of its net interest income by managing the relationship of interest-sensitive assets to interest-sensitive liabilities. To accomplish this, ASB management uses simulation analysis to monitor and measure the relationship between the balances and repayment and repricing characteristics of interest-sensitive assets and liabilities. Specifically, simulation analysis is used to measure net interest income and net market value fluctuations in various interest-rate scenarios. See “Item 3. Quantitative and qualitative disclosures about market risk.” In order to manage its interest-rate risk profile, ASB has utilized the following strategies: (1) increasing the level of low-cost core deposits; (2) originating relatively short-term or variable-rate business banking and commercial real estate loans; (3) investing in mortgage-related securities with short average lives; and (4) taking advantage of the lower interest-rate environment by lengthening the maturities of interest-bearing liabilities. The shape of the yield curve and the difference between the short-term and long-term rates are also factors affecting profitability. For example, if a long-term fixed rate earning asset was funded by a short-term costing liability, the interest rate spread would be higher in a “steep” yield curve than a “flat” yield curve interest-rate environment.

In response to pressure on interest rate spreads as a result of the low interest rate environment, ASB restructured a total of $389 million of FHLB advances during the second quarter of 2003. See “Restructuring of Federal Home Loan Bank Advances” in note (4) of HEI’s notes to consolidated financial statements. The restructuring will result in a reduction of interest expense on these FHLB advances for 2003, which will partially offset the reduction in interest income that ASB has been experiencing.

Regulation

ASB is subject to extensive regulation, principally by the OTS and the Federal Deposit Insurance Corporation. Depending on ASB’s level of regulatory capital and other considerations, these regulations could restrict the ability of ASB to compete with other institutions and to pay dividends to its shareholders. See the discussions below under “Liquidity and capital resources—Bank.”

For a discussion of securities deemed impermissible investments by the OTS, see “Disposition of certain debt securities” in note (4) of HEI’s notes to consolidated financial statements.

Other

(in thousands)	Three months ended September 30,						% change	Primary reason(s) for significant change
(in thousands)	2003			2002			% change	Primary reason(s) for significant change
Revenues	$	683		$	(1,798	)	NM	No writedown of income notes and equity in net income of UTECH Venture Capital Corporation (UTECH) ($0.1 million) in the third quarter of 2003 compared to a writedown of income notes of $1.7 million and equity in net loss of UTECH ($0.4 million) in the third quarter of 2002

Operating loss		(3,517	)		(6,417	)	45	See explanation for revenues and lower income note litigation expense

(in thousands)	Nine months ended September 30,						% change	Primary reason(s) for significant change
(in thousands)	2003			2002			% change	Primary reason(s) for significant change
Revenues	$	2,829		$	(2,278	)	NM	No writedown of income notes, a $0.5 million gain on interest rate swaps and equity in net income of UTECH ($0.1 million) in the first nine months of 2003 compared to a writedown of income notes of $3.7 million, a $0.3 million loss on interest rate swaps and equity in net loss of UTECH ($0.3 million) in the first nine months of 2002

Operating loss		(11,323	)		(14,284	)	21	See explanation for revenues, partly offset by higher general and administrative expense (including stock option and retirement benefits expenses)

NM Not meaningful.

The “other” business segment includes results of operations of HEI Investments, Inc., a company primarily holding investments in leveraged leases (excluding foreign investments reported in discontinued operations); Pacific Energy Conservation Services, Inc., a contract services company primarily providing windfarm operational and maintenance services to an affiliated electric utility; ProVision Technologies, Inc., a company formed to sell, install, operate and maintain on-site power generation equipment and auxiliary appliances in Hawaii and the Pacific Rim, the stock of which was sold for a nominal loss in July 2003; HEI Properties, Inc., a company currently holding passive investments; Hawaiian Electric Industries Capital Trust I, HEI Preferred Funding, LP and Hycap Management, Inc., financing entities formed to effect the issuance of 8.36% Trust Originated Preferred Securities; TOOTS, a maritime freight transportation company that ceased operations in 1999; other inactive subsidiaries; HEI and HEIDI, holding companies; and eliminations of intercompany transactions.

Discontinued operations

In the second quarter of 2003, HEIPC wrote down its remaining Philippines investment from $7 million to $2 million and increased its reserve for future expenses by $1 million, resulting in a $4 million after tax reduction of HEI’s net income for the first nine months of 2003. The HEIPC Group is currently in substantive negotiations with a potential buyer for HEIPC Philippine Development, LLC, the HEIPC Group company that holds its interest in CEPALCO. See note (5) in HEI’s “Notes to consolidated financial statements.”

Contingencies

See note (8) in HEI’s “Notes to consolidated financial statements.”

Recent accounting pronouncements and interpretations

See note (7) and note (6) in HEI’s and HECO’s respective “Notes to consolidated financial statements.”

FINANCIAL CONDITION

Liquidity and capital resources

HEI and HECO believe that their ability to generate cash, both internally primarily from electric utility and (in the case of HEI) banking operations and externally from issuances of equity and debt securities, commercial paper and bank borrowings, is adequate to maintain sufficient liquidity to fund construction programs 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 FHLB of Seattle) was as follows:

(in millions)	September 30, 2003				December 31, 2002
Long-term debt	$	1,064	45	%	$	1,106	46	%
HEI- and HECO-obligated preferred securities of trust subsidiaries		200	9			200	9
Preferred stock of subsidiaries		34	1			34	1
Common stock equity		1,067	45			1,046	44

	$	2,365	100	%	$	2,386	100	%

As of November 1, 2003, the Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HEI and HECO securities were as follows:

	S&P	Moody’s
HEI
Commercial paper	A-2	P-2
Medium-term notes (senior unsecured)	BBB	Baa2
HEI-obligated preferred securities of trust subsidiary	BB+	Ba1

HECO
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)	NR	Baa3

NR Not rated.

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.

In May 2002, S&P revised its credit outlook on HEI and HECO securities to stable from negative, citing “recovery in Hawaii’s economy, moderate construction spending, aggressive cost containment, limited competitive pressures, steady banking operations, and expectations for continued financial improvement.” In June 2001, Moody’s had revised its credit outlook on HEI and HECO securities to stable from negative, citing “significant improvements in the Hawaiian economy, the resulting strong financial performance of the company’s main operating subsidiaries, and a reduced emphasis on overseas investments.”

The rating agencies use a combination of qualitative measures (i.e., assessment of business risk that incorporates an analysis of the qualitative factors of management, competitive positioning, operations, markets and regulation) as well as quantitative measures (e.g., cash flow, debt, interest coverage and liquidity ratios) in determining the ratings of HEI and HECO securities.

On March 7, 2003, HEI sold $50 million of 4% notes, due March 7, 2008, and $50 million of 5.25% notes, due March 7, 2013 under its registered medium-term note program. The net proceeds from the sales were invested in

short-term investments pending their ultimate application, along with other corporate funds, to repay $100 million of notes (which effectively bore interest at three-month LIBOR plus 376.5 basis points after taking into account two interest rate swaps entered into by HEI with Bank of America) at maturity on April 15, 2003. At September 30, 2003, an additional $200 million principal amount of notes were available for offering by HEI under the registered program.

From time to time, HEI and HECO each utilizes short-term debt, principally commercial paper, to support normal operations and for other temporary requirements. From time to time, HECO also borrows short-term from HEI for itself and on behalf of HELCO and MECO, and HECO has also borrowed short-term from MECO. HECO had no short-term borrowings from HEI, but did have $28 million of short-term borrowings from MECO at September 30, 2003. HEI had no commercial paper outstanding during the first nine months of 2003. HECO had an average outstanding balance of commercial paper for the first nine months of 2003 of $0.5 million, but no commercial paper outstanding at September 30, 2003. Management believes that if HEI’s and HECO’s commercial paper ratings were to be downgraded, they might not be able to sell commercial paper under current market conditions.

At September 30, 2003, HEI and HECO maintained bank lines of credit totaling $70 million and $90 million, respectively (all maturing in 2004). These lines of credit are principally maintained by HEI and HECO to support the issuance of commercial paper and also may be drawn for general corporate purposes. Accordingly, the lines of credit are available for short-term liquidity in the event a rating agency downgrade were to reduce or eliminate access to the commercial paper markets. Lines of credit to HEI totaling $40 million contain provisions for revised pricing in the event of a ratings change (e.g., a ratings downgrade of HEI medium-term notes from BBB/Baa2 to BBB-/Baa3 by S&P and Moody’s, respectively, would result in a 25 to 50 basis points higher interest rate; a ratings upgrade from BBB/Baa2 to BBB+/Baa1 by S&P and Moody’s, respectively, would result in a 20 to 25 basis points lower interest rate). There are no such provisions in the other lines of credit available to HEI and HECO. Further, none of HEI’s or HECO’s line of credit agreements contain “material adverse change” clauses that would affect access to the lines of credit in the event of a ratings downgrade. At September 30, 2003, the lines were unused. To the extent deemed necessary, HEI and HECO anticipate arranging similar lines of credit as existing lines of credit mature.

For the first nine months of 2003, net cash provided by operating activities of consolidated HEI was $227 million. Net cash used in investing activities was $277 million, primarily due to ASB’s purchase of mortgage-related securities and origination and purchase of loans, net of repayments and sales of such securities, and HECO’s consolidated capital expenditures. Net cash provided by financing activities was $43 million as a result of several factors, including net increases in securities sold under agreements to repurchase and deposit liabilities and proceeds from the issuance of common stock, partly offset by a net decrease in advances from the FHLB and long-term debt and the payment of common stock dividends and trust preferred securities distributions.

Forecast HEI consolidated “net cash used in investing activities” (excluding “investing” cash flows from ASB) for 2003 through 2007 consists primarily of the net capital expenditures of HECO and its subsidiaries. In addition to the funds required for the electric utilities’ construction program (see discussion below), approximately $0.3 billion will be required for 2003 through 2007 for maturities of HEI long-term debt, which is expected to be replaced primarily with medium-term notes.

Following is a discussion of the liquidity and capital resources of HEI’s largest segments.

Electric utility

HECO’s consolidated capital structure was as follows:

(in millions)	September 30, 2003				December 31, 2002
Short-term borrowings	$	—	—	%	$	6	—	%
Long-term debt		699	39			705	40
HECO-obligated preferred securities of trust subsidiaries		100	6			100	6
Preferred stock		34	2			34	2
Common stock equity		937	53			923	52

	$	1,770	100	%	$	1,768	100	%

Operating activities provided $165 million in net cash during the first nine months of 2003. Investing activities used net cash of $73 million for capital expenditures, net of contributions in aid of construction. Financing activities

used net cash of $66 million, primarily due to the payment of $49 million in common and preferred dividends and preferred securities distributions, a $7 million net decrease in long-term debt and a $6 million net decrease in short term borrowings from HEI.

In September 2002, the Department of Budget and Finance of the State of Hawaii issued, at a small discount, Series 2002A SPRB in the principal amount of $40 million with a maturity of 30 years and a fixed coupon interest rate of 5.10% (yield of 5.15%), and loaned the proceeds from the sale to HECO for its capital improvement projects. As of September 30, 2003, approximately $15 million of proceeds from the Series 2002A sale of SPRB remain undrawn.

On May 1, 2003, the Department of Budget and Finance of the State of Hawaii issued, at a small discount, Refunding Series 2003A SPRB in the aggregate principal amount of $14 million with a maturity of approximately 17 years and a fixed coupon interest rate of 4.75% (yield of 4.85%), and loaned the proceeds from the sale to HELCO. Also on May 1, 2003, the Department of Budget and Finance issued, at par, Refunding Series 2003B SPRB in the aggregate principal amount of $52 million with a maturity of approximately 20 years and a fixed coupon interest rate of 5.00% and loaned the proceeds from the sale to HECO and HELCO. The proceeds of these Refunding SPRB, together with additional funds provided by HECO and HELCO, have been applied to refund a like principal amount of SPRB bearing higher interest coupons (HELCO’s $4 million of 7.60% Series 1990B SPRB and $10 million of 7.375% Series 1990C SPRB with original maturities in 2020, and HECO’s and HELCO’s aggregate $52 million of 6.55% Series 1992 SPRB with original maturities in 2022) on June 2, 2003.

The electric utilities’ net capital expenditures and long-term debt repayments for 2003 through 2007 are estimated to total $0.7 billion. HECO’s consolidated cash flows from operating activities (net income, adjusted for noncash income and expense items such as depreciation, amortization and deferred taxes), after the payment of common stock and preferred stock dividends, are expected to provide cash in excess of the forecast consolidated net capital expenditures and long-term debt repayments and may be used to maintain low levels of future short-term borrowings. HECO does not anticipate the need to issue common equity over the five-year period 2003 through 2007. Debt and/or equity financing may be required, however, to fund unanticipated expenditures not included in the 2003 through 2007 forecast, such as increases in the costs of or an acceleration of the construction of capital projects, unbudgeted acquisitions or investments in new businesses and significant increases in retirement benefit funding requirements that may be required if the market value of pension plan assets does not increase or there are changes in actuarial assumptions. The PUC must approve issuances, if any, of equity and long-term debt securities by HECO, HELCO and MECO.

Capital expenditures include the costs of projects that are required to meet expected load growth, to improve reliability and to replace and upgrade existing equipment. Net capital expenditures for the five-year period 2003 through 2007 are currently estimated to total $0.7 billion. Approximately 53% of forecast gross capital expenditures (which includes AFUDC and capital expenditures funded by third-party contributions in aid of construction) is for transmission and distribution projects, with the remaining 47% primarily for generation projects.

For 2003, electric utility net capital expenditures are estimated to be $158 million. Gross capital expenditures are estimated to be $183 million, including approximately $103 million for transmission and distribution projects, approximately $58 million for generation projects and approximately $22 million for general plant and other projects. Drawdowns of the remaining proceeds from the Series 2002A sale of tax-exempt special purpose revenue bonds, and cash flows from operating activities are expected to provide the cash needed for the net capital expenditures in 2003.

Management periodically reviews capital expenditure estimates and the timing of construction projects. These estimates may change significantly as a result of many considerations, including changes in economic conditions, changes in forecasts of KWH sales and peak load, the availability of purchased power and changes in expectations concerning the construction and ownership of future generating units, the availability of generating sites and transmission and distribution corridors, the ability to obtain adequate and timely rate increases, escalation in construction costs, the impacts of DSM programs, the effects of opposition to proposed construction projects and requirements of environmental and other regulatory and permitting authorities.

Bank

(in millions)	September 30, 2003		December 31, 2002		% change
Total assets	$	6,456	$	6,329	2	%
Available-for-sale mortgage-related securities		2,726		2,737	—
Held-to-maturity investment securities		93		90	4
Loans receivable, net		3,142		2,994	5
Deposit liabilities		3,953		3,801	4
Securities sold under agreements to repurchase		788		667	18
Advances from Federal Home Loan Bank		1,037		1,176	(12	)

As of September 30, 2003, ASB was the third largest financial institution in Hawaii based on total assets of $6.5 billion and deposits of $4.0 billion.

ASB’s principal sources of liquidity are customer deposits, wholesale borrowings, the sale of mortgage loans into secondary market channels and the maturity and repayment of portfolio loans and mortgage-related securities. ASB’s deposits increased by $152 million during the first nine months of 2003. ASB’s principal sources of borrowings are advances from the FHLB and securities sold under agreements to repurchase from broker/dealers. At September 30, 2003, FHLB borrowings totaled $1.0 billion, representing 16% of total assets. ASB is approved by the FHLB to borrow up to 35% of total assets to the extent it provides qualifying collateral and holds sufficient FHLB stock. At September 30, 2003, ASB’s unused FHLB borrowing capacity was approximately $1.2 billion. At September 30, 2003, securities sold under agreements to repurchase totaled $0.8 billion. ASB utilizes growth in deposits, advances from the FHLB and securities sold under agreements to repurchase to fund maturing deposits and deposit withdrawals, repay maturing borrowings, fund existing and future loans and make investments. At September 30, 2003, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $0.8 billion. Management believes ASB’s current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.

In September 2003, ASB entered into an arrangement to have excess funds in its correspondent bank account with Bank of America swept into a Federal Funds Sold facility. Funds earn the overnight fed funds rate and are re-deposited into ASB’s correspondent bank account the next day. This automatic sweep facility offers ASB an operationally efficient method for investing its liquidity and provides a slightly higher rate of return than methods used in the past (deposits with the FHLB). In addition, efficiencies gained using this method have enabled ASB to expand its wire transfer operating hours.

For the first nine months of 2003, net cash provided by ASB’s operating activities was $59 million. Net cash used in ASB’s investing activities was $202 million, primarily due to the purchase of mortgage-related securities and origination and purchase of loans, net of repayments and sales of such securities. Net cash provided by financing activities was $113 million largely due to net increases of $125 million in securities sold under agreements to repurchase and $152 million in deposit liabilities, partly offset by a net decrease of $139 million in advances from the FHLB and the payment of $24 million in common and preferred stock dividends. In the first nine months of 2003, cash from the net increase in deposits and securities sold under agreements to repurchase were used largely to purchase mortgage-related securities, to originate and purchase loans and to repay advances from the FHLB.

ASB believes that a satisfactory regulatory capital position provides a basis for public confidence, affords protection to depositors, helps to ensure continued access to capital markets on favorable terms and provides a foundation for growth. FDIC regulations restrict the ability of financial institutions that are not well-capitalized to compete on the same terms as well-capitalized institutions, such as by offering interest rates on deposits that are significantly higher than the rates offered by competing institutions. As of September 30, 2003, ASB was well-capitalized (ratio requirements noted in parentheses) with a leverage ratio of 6.9% (5.0%), a Tier-1 risk-based capital ratio of 14.0% (6.0%) and a total risk-based capital ratio of 15.3% (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 its control and could cause future results of operations to differ materially from historical results. Such factors include international, national and local economic conditions; competition in its principal segments; developments in the U.S. capital markets; weather; terrorist acts; health-related crises; interest-rate environment; loan loss experience; technological developments; final costs of exits from discontinued operations; asset dispositions; insurance coverages; environmental matters; regulation of electric utility rates; deliveries of fuel oil and purchased power; other electric utility regulatory and permitting contingencies; and regulation of ASB. For additional information about these factors, see pages 20 to 27 of HEI’s 2002 Annual Report to Stockholders (HEI Exhibit 13.1 to HEI’s Current Report on Form 8-K dated February 25, 2003, File No. 1-8503) and pages 13 to 18 of HECO’s 2002 Annual Report (HECO Exhibit 13.2 to HECO’s Current Report on Form 8-K dated February 25, 2003, File No. 1-4955).

Additional factors that may affect future results and financial condition are described on page v under “Forward-looking statements and risk factors.”

MATERIAL ESTIMATES AND CRITICAL ACCOUNTING POLICIES

In preparing the consolidated financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. Actual results could differ significantly from those estimates.

Material estimates that are particularly susceptible to significant change in the case of the Company include the amounts reported for investment securities, allowance for loan losses, regulatory assets, pension and other postretirement benefit obligations, reserves for discontinued operations, current and deferred taxes, contingencies and litigation.

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 27 to 31 of HEI’s 2002 Annual Report to Stockholders (HEI Exhibit 13.1 to HEI’s Current Report on Form 8-K dated February 25, 2003, File No. 1-8503) and pages 18 to 21 of HECO’s 2002 Annual Report (HECO Exhibit 13.2 to HECO’s Current Report on Form 8-K dated February 25, 2003, File No. 1-4955).

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 31 to 36 of HEI’s 2002 Annual Report to Stockholders (HEI Exhibit 13.1 to HEI’s Current Report on Form 8-K dated February 25, 2003, File No. 1-8503).

ASB’s interest-rate risk sensitivity measures as of September 30, 2003 and December 31, 2002 constitute “forward-looking statements” and were as follows:

	September 30, 2003						December 31, 2002
	Change in net interest income (NII)		Net portfolio value (NPV) ratio		NPV ratio sensitivity (change from base case in basis points)		Change in NII		NPV ratio		NPV ratio sensitivity (change from base case in basis points)
Change in interest rates (basis points)
+300	(3.6	)%	5.43	%	(377	)	1.9	%	7.90	%	(235	)
+200	(1.4	)	6.88		(232	)	3.0		9.15		(110	)
+100	0.4		8.17		(103	)	3.3		10.01		(24	)
Base	—		9.20		—		—		10.25		—
-100	(3.1	)	9.70		50		(5.7	)	10.02		(23	)

Management believes that ASB’s interest-rate risk position at September 30, 2003 represents a reasonable level of risk. The September 30, 2003 NII profile is more representative of a “liability sensitive” profile than the December 31, 2002 NII profile. NII remains essentially flat in the +100 bp scenario, and falls in the +200 and +300 bp scenarios. The primary reason for the change in profile is a change in the expected average life of ASB’s mortgage related assets. Record low interest rates during the year provided the opportunity for many borrowers to refinance into new mortgages at very low rates. If interest rates remain unchanged or increase, there would be little or no economic incentive for holders of these loans to prepay, resulting in a longer expected average life for these assets. Given the longer expected average life, there is less opportunity for the assets to reprice upwards in the rising interest rate scenarios. Because ASB’s liabilities tend to have shorter maturities or reprice more frequently than its assets, its net interest margin will tend to decrease as interest rates increase. Thus, rising interest rates could have an adverse effect on ASB’s net income absent mitigating actions that ASB management may take.

ASB’s NPV ratio sensitivity measures the sensitivity of its NPV ratio to changes in interest rates. The magnitude of the NPV sensitivity measures as of September 30, 2003 has increased compared to the magnitude of the sensitivity measures as of December 31, 2002, representing an increase in sensitivity. The increase in sensitivity also results in lower NPV ratios as of September 30, 2003. The increase in sensitivity is a result of the longer expected average life of ASB’s mortgage assets. Financial instruments with longer maturities, or average lives, lose more in value as interest rates rise than instruments with shorter maturities. As the expected average life of its assets increases relative to its liabilities, ASB’s NPV ratio becomes more sensitive to changes in interest rates.

The computation of the prospective effects of hypothetical interest rate changes in the NII sensitivity, NPV ratio, and NPV ratio sensitivity analyses is based on numerous assumptions, including relative levels of market interest rates, loan prepayments, actual 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.

Item 4.

Controls and procedures

HEI

Robert F. Clarke, HEI Chief Executive Officer, and Eric K. Yeaman, HEI Chief Financial Officer, have evaluated the disclosure controls and procedures of HEI as of September 30, 2003. Based on their evaluations, as of September 30, 2003, 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) are effective.

HECO

T. Michael May, HECO Chief Executive Officer, and Richard A. von Gnechten, HECO Chief Financial Officer, have evaluated the disclosure controls and procedures of HECO as of September 30, 2003. Based on their evaluations, as of September 30, 2003, 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) are effective.

PART II–OTHER INFORMATION

Item 1.

Legal proceedings

There are no significant developments in pending legal proceedings except as set forth in HEI’s and HECO’s “Notes to consolidated financial statements” and management’s discussion and analysis of financial condition and results of operations. 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 5.

Other information

A.	Ratio of earnings to fixed charges

HEI and Subsidiaries

Ratio of earnings to fixed charges excluding interest on ASB deposits

Nine months ended September 30, 2003	Years ended December 31,
Nine months ended September 30, 2003	2002	2001	2000	1999	1998
2.01	2.03	1.82	1.76	1.83	1.88

Ratio of earnings to fixed charges including interest on ASB deposits

Nine months ended September 30, 2003	Years ended December 31,
Nine months ended September 30, 2003	2002	2001	2000	1999	1998
1.76	1.72	1.52	1.49	1.50	1.48

For purposes of calculating the ratio of earnings to fixed charges, “earnings” represent the sum of (i) pretax income from continuing operations (excluding undistributed net income or net loss from less than 50%-owned persons) and (ii) fixed charges (as hereinafter defined, but excluding capitalized interest). “Fixed charges” are calculated both excluding and including interest on ASB’s deposits during the applicable periods and represent the sum of (i) interest, whether capitalized or expensed, but excluding interest on nonrecourse debt from leveraged leases which is not included in interest expense in HEI’s consolidated statements of income, (ii) amortization of debt expense and discount or premium related to any indebtedness, whether capitalized or expensed, (iii) the interest factor in rental expense, (iv) the preferred stock dividend requirements of HEI’s subsidiaries, increased to an amount

representing the pretax earnings required to cover such dividend requirements and (v) the preferred securities distribution requirements of trust subsidiaries.

HECO and Subsidiaries

Ratio of earnings to fixed charges

Nine months ended September 30, 2003	Years ended December 31,
Nine months ended September 30, 2003	2002	2001	2000	1999	1998
3.23	3.71	3.51	3.39	3.09	3.33

For purposes of calculating the ratio of earnings to fixed charges, “earnings” represent the sum of (i) pretax income before preferred stock dividends of HECO and (ii) fixed charges (as hereinafter defined, but excluding the allowance for borrowed funds used during construction). “Fixed charges” represent the sum of (i) interest, whether capitalized or expensed, incurred by HECO and its subsidiaries, (ii) amortization of debt expense and discount or premium related to any indebtedness, whether capitalized or expensed, (iii) the interest factor in rental expense, (iv) the preferred stock dividend requirements of HELCO and MECO, increased to an amount representing the pretax earnings required to cover such dividend requirements and (v) the preferred securities distribution requirements of the trust subsidiaries.

B.	Puna Geothermal Venture (PGV)

HELCO has a 35-year PPA with PGV for 30 MW of firm capacity from its geothermal steam facility expiring on December 31, 2027. PGV’s output was reduced to 6 MW from April 2002 to March 2003. The loss of generation has been attributed to blockage of a source well due to a failed liner 5,000 feet below the earth’s surface and decreasing steam quality emanating from one of PGV’s source wells. PGV completed drilling an additional source well in February 2003, and converted the blocked source well into an injection well in early March 2003. The new injection well was tested and PGV’s capacity is currently between 25 to 28 MW. PGV obtained a permit from the DOH for the new injection well in March 2003. Without the new injection well, PGV was able to produce only about 10 to 11 MW due to the high moisture content of the steam from the new source well. PGV is assessing whether to drill another source well or to install new generation equipment designed to utilize the lower quality steam. While PGV indicates it is evaluating its options to enable it to restore its 30 MW commitment to HELCO as soon as possible, HELCO cannot predict when PGV will be able to meet its contractual commitment. HELCO’s PPA with PGV provides for annual availability sanctions against PGV if PGV does not provide up to the contracted 30 MW of capacity. In the first quarter ending March 31, 2003, HELCO recorded $0.7 million lower purchased power expense from PGV for availability sanctions for not meeting contracted capacity for 2002. In addition, since PGV had not yet restored its 30 MW commitment to HELCO by September 30, 2003, availability sanctions for 2003 may be assessed against PGV in 2004. The amount of availability sanctions is dependent on when PGV reaches its contractual commitment.

C.	Hamakua Energy Partners. L.P. (Hamakua Partners)

HELCO has a PPA to purchase up to 60 MW (net) of firm capacity with Hamakua Partners. In September 2003, J. A. Jones, Inc. (Jones) filed for reorganization in bankruptcy in North Carolina. Jones is the parent company of the managing general partner and a limited partner of Hamakua Partners, and is one of the two co-guarantors of the Hamakua Partners project. Jones has stated that the bankruptcy filing will have no impact on Hamakua Partners’ ability to meet its contractual commitments. HELCO is continuing to evaluate the possible implications of the bankruptcy filing.

D.	AES Hawaii

In March 1988, HECO entered into a PPA with AES Barbers Point, Inc. (now known as AES Hawaii), a Hawaii-based, indirect subsidiary of The AES Corporation. The agreement with AES Hawaii, as amended in August 1989, provides that, for a period of 30 years beginning September 1992, HECO will purchase 180 MW of firm capacity. Under the amended PPA, AES Hawaii must obtain certain consents from HECO prior to entering into any arrangement to refinance the facility. In the second quarter of 2003, HECO and AES Hawaii reached agreement on the terms upon which HECO would consent to a proposed refinancing. Under the agreement, which was contingent

on obtaining certain PUC approvals and completion of the refinancing, HECO received consideration for its consent, primarily in the form of a PPA amendment that reduces the cost of firm capacity supplied to HECO pursuant to the PPA, retroactive to June 1, 2003. The benefit of the firm capacity cost reduction, totaling approximately $2.9 million annually for the remaining term of the PPA, is being passed on to ratepayers through a reduction in rates. AES Hawaii also has granted HECO an option, subject to certain conditions, to acquire an interest in portions of the AES Hawaii facility site that are not needed for the existing plant operations, and which potentially could be used for the development of another coal-fired facility. On July 1, 2003, the PUC issued a D&O approving the PPA amendment and the establishment of a rate adjustment (lowering rates) on short notice, and, on July 9, 2003, the PUC issued a D&O clarifying its July 1, 2003 D&O. On July 31, 2003, the proposed refinancing was completed and capacity payments were reduced, retroactive to June 1, 2003.

E.	HECO’s integrated resource plan

In September 2003, the PUC at the joint request of HECO and the Consumer Advocate opened a docket to commence HECO’s third integrated resource plan (IRP), which is required to be submitted no later than October 31, 2005.

HECO expects its third IRP will require multiple solutions to meet Oahu’s future energy needs, including renewable energy resources, energy efficiency, conservation, technology (such as CHP) and central station generation. Given the lead times needed for permitting and regulatory approvals, in October 2003, HECO submitted a covered source permit application with the DOH for a 107 MW simple cycle combustion turbine in Campbell Industrial Park, which could be added as a peaking unit in the event new central generation will be required in 2009, or earlier if reductions in energy use achieved by DSM programs are less than currently planned, as indicated in HECO’s second IRP. The application specifies that the unit would use diesel fuel oil or naphtha, with ability to convert to a bio-fuel, like ethanol, when it becomes commercially available.

F.	HECO-obligated preferred securities of trust subsidiaries

On October 27, 2003, HEI issued a news release, “Hawaiian Electric Industries, Inc. reports third quarter 2003 earnings.” In the release, HEI and HECO had characterized the third quarter 2003 distributions of the mandatorily redeemable securities of HECO’s trust subsidiaries as “interest expense” in their respective consolidated income statements in accordance with management’s interpretation of the requirements of SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity,” at that time. Subsequently, on October 29, 2003, the FASB met and indefinitely deferred the effective date of the provisions of SFAS No. 150 related to classification and measurement requirements for mandatorily redeemable financial instruments that become subject to SFAS No. 150 solely as a result of consolidation. Thus, in this Form 10-Q, HEI and HECO have characterized the third quarter 2003 distributions of the mandatorily redeemable securities of HECO’s trust subsidiaries as it did before SFAS No. 150, i.e. as “preferred securities distributions of trust subsidiaries,” in their respective consolidated income statements.

Item 6.

Exhibits and reports on Form 8-K

(a) Exhibits


HEI Exhibit 12.1		Hawaiian Electric industries, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, nine months ended September 30, 2003 and 2002 and years ended December 31, 2002, 2001, 2000, 1999 and 1998

HEI Exhibit 31.1		Certification Pursuant to Section 13a-14 of the Securities and Exchange Act of 1934 of Robert F. Clarke (HEI Chief Executive Officer)

HEI Exhibit 31.2		Certification Pursuant to Section 13a-14 of the Securities and Exchange Act of 1934 of Eric K. Yeaman (HEI Chief Financial Officer)

HEI Exhibit 32.1		Written Statement of Robert F. Clarke (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

HEI Exhibit 99		Eighth Amendment to Trust Agreement, made and entered into September 1, 2003, between HEI and Fidelity Management Trust Company for the Hawaiian Electric Industries Retirement Savings Plan for incorporation by reference in the Registration Statement on Form S-8 (Regis. No. 333-02103)

HECO Exhibit 12.2		Hawaiian Electric Company, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, nine months ended September 30, 2003 and 2002 and years ended December 31, 2002, 2001, 2000, 1999 and 1998

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

HECO Exhibit 31.4		Certification Pursuant to Section 13a-14 of the Securities and Exchange Act of 1934 of Richard von Gnechten (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 Richard von Gnechten (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

(b) Reports on Form 8-K

Subsequent to June 30, 2003, HEI and/or HECO filed Current Reports on Forms 8-K with the SEC as follows:

Dated (filing date)	Registrant/s	Items reported

July 8, 2003 (July 10, 2003)	HEI/HECO	Item 5. HELCO power situation update

July 21, 2003 (July 22, 2003)	HEI/HECO	Items 5, 9 and 12. HEI’s July 21, 2003 news release (HEI reports second quarter 2003 earnings)

August 25, 2003 (August 29, 2003)	HEI/HECO	Item 5. Demand-side management programs-agreements with the Consumer Advocate and Knapp vs. AES case updates

September 5, 2003 (September 15, 2003)	HEI/HECO	Item 5. MECO’s notice and finding of environmental permit violation and competition updates

October 27, 2003 (October 27, 2003)	HEI/HECO	Items 5 and 12. HEI’s October 27, 2003 news release (HEI reports third quarter 2003 earnings)

November 11, 2003 (November 12, 2003)	HEI/HECO	Item 5. HELCO power situation update

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.

(Registrant)

HAWAIIAN ELECTRIC COMPANY, INC.

(Registrant)


By:	/s/ Robert F. Clarke	By:	/s/ T. Michael May

	Robert F. Clarke Chairman, President and Chief Executive Officer (Principal Executive Officer of HEI)		T. Michael May President and Chief Executive Officer (Principal Executive Officer of HECO)


By:	/s/ Eric K. Yeaman	By:	/s/ Richard A. von Gnechten

	Eric K. Yeaman Financial Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer of HEI)		Richard A. von Gnechten Financial Vice President (Principal Financial Officer of HECO)


By:	/s/ Curtis Y. Harada	By:	/s/ Ernest T. Shiraki

	Curtis Y. Harada Controller (Chief Accounting Officer of HEI)		Ernest T. Shiraki Controller (Chief Accounting Officer of HECO)

Date: November 12, 2003