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, 2004

OR

¨ 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 each 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 each 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 issuers’ classes of common stock, as of the latest practicable date.

Class of Common Stock	Outstanding November 1, 2004
Hawaiian Electric Industries, Inc. (Without Par Value)	80,583,763 Shares
Hawaiian Electric Company, Inc. ($6 2/3 Par Value)	12,805,843 Shares (not publicly traded)

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended September 30, 2004

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, 2004 and December 31, 2003	1
	Consolidated statements of income (unaudited)—three and nine months ended September 30, 2004 and 2003	2
	Consolidated statements of changes in stockholders’ equity (unaudited)—nine months ended September 30, 2004 and 2003	3
	Consolidated statements of cash flows (unaudited)—nine months ended September 30, 2004 and 2003	4
	Notes to consolidated financial statements (unaudited)	5
	Hawaiian Electric Company, Inc. and Subsidiaries
	Consolidated balance sheets (unaudited)—September 30, 2004 and December 31, 2003	16
	Consolidated statements of income (unaudited)—three and nine months ended September 30, 2004 and 2003	17
	Consolidated statements of retained earnings (unaudited)—three and nine months ended September 30, 2004 and 2003	17
	Consolidated statements of cash flows (unaudited)—nine months ended September 30, 2004 and 2003	18
	Notes to consolidated financial statements (unaudited)	19
Item 2.	Management’s discussion and analysis of financial condition and results of operations	41
Item 3.	Quantitative and qualitative disclosures about market risk	68
Item 4.	Controls and procedures	70
PART II – OTHER INFORMATION
Item 1.	Legal proceedings	70
Item 2.	Unregistered sales of equity securities and use of proceeds	70
Item 5.	Other information	71
Item 6.	Exhibits	75
Signatures		76

i

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended September 30, 2004

GLOSSARY 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 (dissolved in January 2004), 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 (dissolved in April 2004)*, HECO Capital Trust II (dissolved in April 2004)*, HECO Capital Trust III*, Renewable Hawaii, Inc., HEI Diversified, Inc., American Savings Bank, F.S.B. and its subsidiaries, Pacific Energy Conservation Services, Inc., HEI 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 (dissolved in April 2004)*, Hawaiian Electric Industries Capital Trust II*, Hawaiian Electric Industries Capital Trust III*, HEI Preferred Funding, LP (dissolved in April 2004)*, The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.), HEI Power Corp. and its subsidiaries (discontinued operations, except for subsidiary HEI Investments, Inc.) and Malama Pacific Corp. (discontinued operations, dissolved in June 2004) (*unconsolidated subsidiaries in 2004)
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

ii

GLOSSARY OF TERMS (continued)

Terms	Definitions
DRIP	HEI Dividend Reinvestment and Stock Purchase Plan
DSM	Demand-side management
EIS	Environmental Impact Statement
EITF	Emerging Issues Task Force
EPA	Environmental Protection Agency—federal
FASB	Financial Accounting Standards Board
Federal	U.S. Government
FHLB	Federal Home Loan Bank
FIN	FASB Interpretation No.
GAAP	Accounting principles generally accepted in the United States of America
HECO	Hawaiian Electric Company, Inc., an electric utility subsidiary of Hawaiian Electric Industries, Inc. and parent company of Maui Electric Company, Limited, Hawaii Electric Light Company, Inc., Renewable Hawaii, Inc., HECO Capital Trust I (dissolved in April 2004)*, HECO Capital Trust II (dissolved in April 2004)* and HECO Capital Trust III* (*unconsolidated subsidiaries in 2004)
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 (dissolved in April 2004)*, 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. (discontinued operations, except for subsidiary HEI Investments, Inc.) and Malama Pacific Corp. (discontinued operations, dissolved in June 2004) (*unconsolidated subsidiaries in 2004)
HEIDI	HEI Diversified, Inc., a wholly owned subsidiary of Hawaiian Electric Industries, Inc. and the parent company of American Savings Bank, F.S.B.
HEIII	HEI Investments, Inc. (formerly HEI Investment Corp.), a subsidiary of HEI Power Corp.
HEIPC	HEI Power Corp., a wholly owned subsidiary of Hawaiian Electric Industries, Inc., and the parent company of numerous subsidiaries, several of which were dissolved or otherwise wound up in 2002 and 2003 pursuant to a formal plan to exit the international power business (engaged in by HEIPC and its subsidiaries) adopted by the HEI Board of Directors in October 2001
HEIPC Group	HEI Power Corp. and its subsidiaries
HEIRSP	Hawaiian Electric Industries Retirement Savings Plan
HEI’s 2003 Annual Report	Hawaiian Electric Industries, Inc.’s 2003 Annual Report to Shareholders (HEI Exhibit 13.1 to HEI’s Current Report on Form 8-K dated February 26, 2004, File No. 1-8503)

iii

GLOSSARY OF TERMS (continued)

Terms	Definitions
HELCO	Hawaii Electric Light Company, Inc., an electric utility subsidiary of Hawaiian Electric Company, Inc.
HTB	Hawaiian Tug & Barge Corp. In November 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 Services, Inc.
IPP	Independent power producer
IRP	Integrated resource plan
kV	Kilovolt
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
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.), a wholly owned subsidiary of Hawaiian Electric Industries, Inc. On November 10, 1999, HTB sold the stock of YB and substantially all of HTB’s operating assets and changed its name.
VIE	Variable interest entity
YB	Young Brothers, Limited, which was sold on November 10, 1999, was formerly a wholly owned subsidiary of Hawaiian Tug & Barge Corp.

iv

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 are also forward-looking statements. Forward-looking statements are based on current expectations and projections about future events and are subject to risks, uncertainties and the accuracy of assumptions concerning HEI and its subsidiaries (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 strength or weakness of the Hawaii and continental U.S. real estate markets (including the fair value of collateral underlying loans and mortgage-related securities) and 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, especially if measures such as demand-side management (DSM), distributed generation, combined heat and power or other firm capacity supply-side resources fall short of achieving their forecast benefits or are otherwise insufficient to reduce or meet forecast peak demand;

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

• 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 fuel supply and 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, including continued regulatory accounting under Statement of Financial Accounting Standards No. 71 and the possible effects of applying new accounting principles applicable to variable interest entities (VIEs) to power purchase arrangements with independent power producers;

• the effects of changes by securities rating agencies in their 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);

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

• the 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;

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

• 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.

v

PART I—FINANCIAL INFORMATION

Item 1.  Financial statements

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)

(dollars in thousands)	September 30, 2004			December 31, 2003
Assets
Cash and equivalents	$	171,631		$	223,310
Federal funds sold		75,941			56,678
Accounts receivable and unbilled revenues, net		203,516			187,716
Available-for-sale investment and mortgage-related securities		1,998,549			1,787,177
Available-for-sale mortgage-related securities pledged for repurchase agreements		916,592			941,571
Held-to-maturity investment securities		97,365			94,624
Loans receivable, net		3,126,277			3,121,979
Property, plant and equipment, net of accumulated depreciation of $1,426,908 and $1,367,538		2,372,884			2,311,888
Other		405,954			382,228
Goodwill and other intangibles		92,185			93,987
	$	9,460,894		$	9,201,158
Liabilities and stockholders’ equity
Liabilities
Accounts payable	$	173,573		$	132,780
Deposit liabilities		4,182,409			4,026,250
Short-term borrowings		8,392			—
Securities sold under agreements to repurchase		790,699			831,335
Advances from Federal Home Loan Bank		1,020,053			1,017,053
Long-term debt, net		1,167,108			1,064,420
Deferred income taxes		233,962			226,590
Regulatory liabilities, net		82,595			71,882
Contributions in aid of construction		231,118			233,969
Other		324,332			273,442
		8,214,241			7,877,721
Minority interests
HEI- and HECO-obligated preferred securities of trust subsidiaries		—			200,000
Preferred stock of subsidiaries—not subject to mandatory redemption		34,406			34,406
		34,406			234,406
Stockholders’ equity
Preferred stock, no par value, authorized 10,000,000 shares; issued: none		—			—
Common stock, no par value, authorized 100,000,000 shares; issued and outstanding: 80,563,717 shares and 75,837,588 shares		1,007,754			888,431
Retained earnings		209,170			197,774
Accumulated other comprehensive income (loss)		(4,677	)		2,826
		1,212,247			1,089,031
	$	9,460,894		$	9,201,158

See accompanying “Notes to Consolidated Financial Statements.”

1

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)

	Three months ended September 30,						Nine months ended September 30,
(in thousands, except per share amounts and ratio of earnings to fixed charges)	2004			2003			2004			2003
Revenues
Electric utility	$	410,077		$	359,250		$	1,127,295		$	1,042,691
Bank		90,296			93,770			269,536			281,575
Other		6,386			683			8,836			2,829
		506,759			453,703			1,405,667			1,327,095
Expenses
Electric utility		357,364			312,614			984,528			912,495
Bank		63,765			68,654			193,886			211,672
Other		3,944			4,200			10,784			14,152
		425,073			385,468			1,189,198			1,138,319
Operating income (loss)
Electric utility		52,713			46,636			142,767			130,196
Bank		26,531			25,116			75,650			69,903
Other		2,442			(3,517	)		(1,948	)		(11,323	)
		81,686			68,235			216,469			188,776
Interest expense—other than bank		(18,376	)		(17,315	)		(58,929	)		(53,174	)
Allowance for borrowed funds used during construction		859			496			2,236			1,385
Preferred stock dividends of subsidiaries		(475	)		(501	)		(1,425	)		(1,504	)
Preferred securities distributions of trust subsidiaries		—			(4,008	)		—			(12,026	)
Allowance for equity funds used during construction		1,934			1,098			5,056			3,075
Income from continuing operations before income taxes		65,628			48,005			163,407			126,532
Income taxes		24,869			17,483			80,478			45,923
Income from continuing operations		40,759			30,522			82,929			80,609
Discontinued operations-gain (loss) on disposal, net of income taxes		1,913			—			1,913			(3,870	)
Net income	$	42,672		$	30,522		$	84,842		$	76,739
Basic earnings (loss) per common share
Continuing operations	$	0.51		$	0.41		$	1.05		$	1.08
Discontinued operations		0.02			—			0.02			(0.05	)
	$	0.53		$	0.41		$	1.07		$	1.03
Diluted earnings (loss) per common share
Continuing operations	$	0.51		$	0.41		$	1.05		$	1.08
Discontinued operations		0.02			—			0.02			(0.05	)
	$	0.53		$	0.41		$	1.07		$	1.03
Dividends per common share	$	0.31		$	0.31		$	0.93		$	0.93
Weighted-average number of common shares outstanding		80,509			75,032			79,204			74,410
Dilutive effect of stock options and dividend equivalents		319			320			245			318
Adjusted weighted-average shares		80,828			75,352			79,449			74,728
Ratio of earnings to fixed charges (SEC method)
Excluding interest on ASB deposits								2.37			2.01
Including interest on ASB deposits								2.05			1.76

See accompanying “Notes to Consolidated Financial Statements.”

2

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Changes in Stockholders’ Equity (unaudited)

(in thousands, except per share amounts)	Common stock			Retained earnings			Accumulated other comprehensive income (loss)			Total
	Shares	Amount
Balance, December 31, 2003	75,838	$	888,431	$	197,774		$	2,826		$	1,089,031
Comprehensive income:
Net income	—		—		84,842			—			84,842
Net unrealized losses on securities:
Net unrealized losses arising during the period, net of tax benefits of $2,621	—		—		—			(3,969	)		(3,969	)
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $2,002	—		—		—			(3,535	)		(3,535	)
Minimum pension liability adjustment, net of tax benefits of $19	—		—		—			1			1
Comprehensive income (loss)	—		—		84,842			(7,503	)		77,339
Issuance of common stock, net	4,726		119,323		—			—			119,323
Common stock dividends ($0.93 per share)	—		—		(73,446	)		—			(73,446	)
Balance, September 30, 2004	80,564	$	1,007,754	$	209,170		$	(4,677	)	$	1,212,247
Balance, December 31, 2002	73,618	$	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	1,762		37,301		—			—			37,301
Common stock dividends ($0.93 per share)	—		—		(69,122	)		—			(69,122	)
Balance, September 30, 2003	75,380	$	876,804	$	183,735		$	6,861		$	1,067,400

See accompanying “Notes to Consolidated Financial Statements.”

3

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)

Nine months ended September 30	2004			2003
(in thousands)
Cash flows from operating activities
Income from continuing operations	$	82,929		$	80,609
Adjustments to reconcile income from continuing operations to net cash provided by operating activities
Depreciation of property, plant and equipment		94,065			90,551
Other amortization		14,135			25,683
Provision for loan losses		(8,400	)		2,775
Deferred income taxes		15,152			(4,609	)
Allowance for equity funds used during construction		(5,056	)		(3,075	)
Gain on sale of income notes		(5,607	)		—
Changes in assets and liabilities
Decrease (increase) in accounts receivable and unbilled revenues, net		(15,806	)		1,719
Increase in accounts payable		40,818			23,004
Increase in taxes accrued		55,968			37,753
Changes in other assets and liabilities		(33,802	)		(28,101	)
Net cash provided by operating activities		234,396			226,309
Cash flows from investing activities
Available-for-sale mortgage-related securities purchased		(863,790	)		(1,899,634	)
Principal repayments on available-for-sale mortgage-related securities		606,356			1,609,048
Proceeds from sale of available-for-sale mortgage-related securities		45,207			243,406
Loans receivable originated and purchased		(869,615	)		(1,121,298	)
Principal repayments on loans receivable		874,548			973,276
Proceeds from sale of real estate acquired in settlement of loans		749			4,073
Capital expenditures		(141,459	)		(94,978	)
Contributions in aid of construction		5,857			10,296
Distributions from unconsolidated subsidiaries		24,379			—
Other		9,889			(723	)
Net cash used in investing activities		(307,879	)		(276,534	)
Cash flows from financing activities
Net increase in deposit liabilities		156,159			151,890
Net increase in short-term borrowings with original maturities of three months or less		8,392			—
Net increase in retail repurchase agreements		20,428			10,710
Proceeds from securities sold under agreements to repurchase		608,650			1,527,575
Repayments of securities sold under agreements to repurchase		(672,650	)		(1,413,275	)
Proceeds from advances from Federal Home Loan Bank		129,200			318,500
Principal payments on advances from Federal Home Loan Bank		(126,200	)		(457,700	)
Proceeds from issuance of long-term debt		102,525			167,360
Repayment of long-term debt		(223,165	)		(210,000	)
Preferred securities distributions of trust subsidiaries		—			(12,026	)
Net proceeds from issuance of common stock		108,356			23,015
Common stock dividends		(68,895	)		(56,172	)
Other		(5,099	)		(6,970	)
Net cash provided by financing activities		37,701			42,907
Net cash provided by (used in) discontinued operations		3,366			(2,929	)
Net decrease in cash and equivalents and federal funds sold		(32,416	)		(10,247	)
Cash and equivalents and federal funds sold, beginning of period		279,988			244,525
Cash and equivalents and federal funds sold, end of period	$	247,572		$	234,278

See accompanying “Notes to Consolidated Financial Statements.”

4

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/A for the year ended December 31, 2003 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, 2004 and June 30, 2004.

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, 2004 and December 31, 2003 and the results of its operations for the three and nine months ended September 30, 2004 and 2003, and its cash flows for the nine months ended September 30, 2004 and 2003. All such adjustments are of a normal recurring nature, unless otherwise disclosed in this note or other notes to accompanying unaudited consolidated financial statements, in this Form 10-Q or in 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. For example, the assets in note 2 at September 30, 2003 have been restated for the reclassification of the accrual for cost of removal (expected to exceed salvage value in the future) of $175 million from accumulated depreciation to regulatory liabilities.

All share and per share amounts in the accompanying unaudited financial statements and related notes, and in this Form 10-Q, have been adjusted for all periods presented to reflect the stock split described in note 9 (unless otherwise noted).

5

(2) Segment financial information

Segment financial information was as follows:

(in thousands)	Electric Utility		Bank	Other		Total
Three months ended September 30, 2004
Revenues from external customers	$	410,077	90,296	6,386		$	506,759
Profit (loss)*	$	42,866	25,154	(2,392	)	$	65,628
Income taxes (benefit)		16,691	9,776	(1,598	)		24,869
Net income (loss)—continuing operations	$	26,175	15,378	(794	)	$	40,759
Nine months ended September 30, 2004
Revenues from external customers	$	1,127,295	269,536	8,836		$	1,405,667
Profit (loss)*	$	110,988	71,519	(19,100	)	$	163,407
Income taxes (benefit)		43,055	47,163	(9,740	)		80,478
Net income (loss)—continuing operations	$	67,933	24,356	(9,360	)	$	82,929
Assets (at September 30, 2004, including net assets of discontinued operations)	$	2,709,323	6,679,989	71,582		$	9,460,894
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
Net income (loss)—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
Net income (loss)—continuing operations	$	56,572	42,277	(18,240	)	$	80,609
Assets (at September 30, 2003, including net assets of discontinued operations)	$	2,537,470	6,455,776	103,737		$	9,096,983

* 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.

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

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

6

(3) Electric utility subsidiary

For HECO’s consolidated financial information, including its commitments and contingencies, see pages 16 through 40.

(4) Bank subsidiary

Selected financial information

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

Consolidated Balance Sheet Data (unaudited)

(in thousands)	September 30, 2004			December 31, 2003
Assets
Cash and equivalents	$	159,088		$	209,598
Federal funds sold		75,941			56,678
Available-for-sale investment and mortgage-related securities		1,998,549			1,775,053
Available-for-sale mortgage-related securities pledged for repurchase agreements		916,592			941,571
Held-to-maturity investment securities		97,365			94,624
Loans receivable, net		3,126,277			3,121,979
Other		213,992			221,718
Goodwill and other intangibles		92,185			93,987
	$	6,679,989		$	6,515,208
Liabilities and stockholders’ equity
Deposit liabilities—noninterest bearing	$	504,371		$	469,272
Deposit liabilities—interest bearing		3,678,038			3,556,978
Securities sold under agreements to repurchase		790,699			831,335
Advances from Federal Home Loan Bank		1,020,053			1,017,053
Other		135,858			97,429
		6,129,019			5,972,067
Minority interests		3,488			3,417
Preferred stock		75,000			75,000
		78,488			78,417
Common stock		245,357			244,568
Retained earnings		230,510			221,109
Accumulated other comprehensive loss		(3,385	)		(953	)
		472,482			464,724
	$	6,679,989		$	6,515,208

7

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

Consolidated Statement of Income Data (unaudited)

(in thousands)	Three months ended September 30,					Nine months ended September 30,
	2004			2003		2004			2003
Interest and dividend income
Interest and fees on loans	$	45,504		$	49,657	$	137,745		$	150,555
Interest on mortgage-related securities		29,608			24,876		84,244			80,176
Interest and dividends on investment securities		1,619			1,428		5,032			4,736
		76,731			75,961		227,021			235,467
Interest expense
Interest on deposit liabilities		11,660			13,099		35,334			41,182
Interest on Federal Home Loan Bank advances		11,143			11,449		31,987			37,067
Interest on securities sold under repurchase agreements		5,345			5,287		15,822			16,059
		28,148			29,835		83,143			94,308
Net interest income		48,583			46,126		143,878			141,159
Provision for loan losses		(3,800	)		600		(8,400	)		2,775
Net interest income after provision for loan losses		52,383			45,526		152,278			138,384
Other income
Fees from other financial services		5,980			6,015		17,722			17,964
Fee income on deposit liabilities		4,619			4,423		13,276			12,257
Fee income on other financial products		2,328			2,426		7,950			7,660
Fee income on loans serviced for others, net		(207	)		1,952		370			508
Gain (loss) on sale of securities		(86	)		1,719		(70	)		4,085
Other income		931			1,274		3,267			3,634
		13,565			17,809		42,515			46,108
General and administrative expenses
Compensation and employee benefits		16,044			16,917		47,503			49,711
Occupancy		4,201			4,256		12,730			12,172
Equipment		3,319			3,763		10,364			10,515
Data processing		2,949			2,549		8,549			7,956
Consulting and other services		3,292			2,732		9,013			10,114
Interest on income taxes		461			–		5,785			195
Other		9,151			8,002		25,199			23,926
		39,417			38,219		119,143			114,589
Income before minority interests and income taxes		26,531			25,116		75,650			69,903
Minority interests		24			48		73			114
Income taxes		9,776			8,440		47,163			23,454
Income before preferred stock dividends		16,731			16,628		28,414			46,335
Preferred stock dividends		1,353			1,353		4,058			4,058
Net income for common stock	$	15,378		$	15,275	$	24,356		$	42,277

At September 30, 2004, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.0 billion.

8

ASB Realty Corporation

In March 1998, ASB formed a subsidiary, ASB Realty Corporation, which elects to be taxed as a real estate investment trust (REIT). This reorganization had reduced Hawaii bank franchise taxes, net of federal income tax benefits, recognized on the financial statements of HEI Diversified, Inc. (HEIDI) and ASB by $21 million (through March 31, 2004) as a result of ASB taking a dividends received deduction on dividends paid to it by ASB Realty Corporation. The State of Hawaii Department of Taxation (DOT) challenged ASB’s position on the dividends received deduction and issued notices of tax assessment for 1999, 2000 and 2001. In October 2002, ASB filed an appeal with the State Board of Review, First Taxation District (Board). In May 2003, the Board heard ASB’s case and issued its decision in favor of the DOT and ASB filed a notice of appeal with the Hawaii Tax Appeal Court. As required under Hawaii law, ASB paid the bank franchise taxes and interest assessed at that time ($17 million) in June 2003, but recorded this payment as a deposit rather than an expense for financial statement purposes.

On May 14, 2004, the parties stipulated to certain factual matters. On May 17, 2004, the DOT and ASB each filed a motion for summary judgment, and both motions were heard on June 7, 2004. At the conclusion of this hearing, the Hawaii Tax Appeal Court orally announced a decision in favor of the DOT and against ASB for tax assessed years 1999 through 2001 and a written judgment against ASB was filed on June 22, 2004. ASB continues to believe that its tax position is proper and has appealed the judgment to the Hawaii Supreme Court. However, as a result of the Tax Appeal Court’s decision, ASB wrote off the deposit recorded in June 2003 and expensed the related bank franchise taxes and interest for subsequent periods through March 31, 2004 related to this issue, resulting in a cumulative charge to net income in the second quarter of 2004 of $24 million ($21 million for the bank franchise taxes and $3 million for interest). In the second and third quarters of 2004, ASB accrued an aggregate of $0.4 million of interest, net of taxes, and state bank franchise tax of $1.2 million, net of taxes, related to this tax issue for the period from April 1 to September 30, 2004.

Restructuring of Federal Home Loan Bank Advances

Because 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, with $258 million of advances restructured in April 2003 and $131 million of advances 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 resulted in a reduction of interest expense on these FHLB advances of approximately $3 million for the remainder of 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 resulted in a reduction of interest expense on these FHLB advances of approximately $1.5 million for the remainder of 2003.

(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.

In 1998 and 1999, the HEIPC Group invested $9.7 million to acquire shares in Cagayan Electric Power & Light Co., Inc. (CEPALCO), an electric distribution company in the Philippines. The HEIPC Group recognized impairment losses of approximately $3 million in 2001 and $5 million in the second quarter of 2003 to adjust this investment to its estimated net realizable values at the time of approximately $7 million and $2 million, respectively. In the first quarter of 2004, the HEIPC Group sold HEIPC Philippine Development, LLC, the HEIPC Group company that held an interest in CEPALCO, for a nominal gain.

9

The HEIPC Group is pursuing the recovery of a substantial portion of the costs incurred in connection with the China joint venture interest. As part of its recovery efforts, in March 2004, the HEIPC Group entered into an agreement to transfer its interest in a China joint venture to its partner and another entity. In the third quarter of 2004, the HEIPC Group received the non-refundable transfer price of $3 million and recorded a gain on disposal, net of income taxes, of $2 million. The transfer of the joint venture interest will occur upon the approval of the Ministry of Commerce in China.

As of September 30, 2004, the remaining net assets of the discontinued international power operations amounted to $9 million (included in “Other” assets) and consisted primarily of deferred taxes receivable, reduced by a reserve for losses from operations during the phase-out period (primarily for legal fees). HEIPC increased its reserve for future expenses by $1 million in each of the second quarter of 2003 and the first quarter of 2004. If the HEIPC Group is successful in recovery of all or part of the remaining costs incurred in connection with its China joint venture interest, such recoveries would be recorded as a gain on disposal of discontinued operations. 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) Medium-term notes

On March 17, 2004, HEI sold $50 million of 4.23% notes, Series D, due March 15, 2011 under its registered medium-term note program. The net proceeds from this sale were ultimately used to make short-term loans to HECO, to assist HECO and HELCO in redeeming the 7.30% Cumulative Quarterly Income Preferred Securities, Series 1998, in April 2004 and for other general corporate purposes. It is anticipated that HECO will repay those short-term loans by the end of 2004 primarily with funds saved from reducing dividends to HEI in 2004.

(7) HEI- and HECO-obligated preferred securities of trust subsidiaries; common stock sale and redemption of trust preferred securities

Through December 31, 2003, HEI had included the financial statements of its subsidiary trust, Hawaiian Electric Industries Capital Trust I (the Trust) and its subsidiary, HEI Preferred Funding, LP (the Partnership), and the financial statements of HECO’s subsidiary trusts, HECO Capital Trusts I and II (see note 2 in HECO’s “Notes to Consolidated Financial Statements”), in its consolidated financial statements, with the trust preferred securities issued by the trusts being classified in HEI’s consolidated balance sheet under the heading “HEI- and HECO-obligated preferred securities of trust subsidiaries.”

In December 2003, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. (FIN) 46R, “Consolidation of Variable Interest Entities,” which addresses whether a business enterprise should consolidate an entity. HEI and its subsidiaries adopted the provisions of FIN 46R in the first quarter of 2004. Under FIN 46R, HEI deconsolidated the Trust and the Partnership and HECO deconsolidated HECO Capital Trusts I and II and never consolidated HECO Capital Trust III (whose trust preferred securities were issued in March 2004).

10

Trust preferred securities issued by HEI’s and HECO’s unconsolidated (effective January 1, 2004) financing subsidiaries were as follows:

(in thousands, except per security amounts and number of securities)	September 30, 2004		December 31, 2003		Liquidation value per security
Hawaiian Electric Industries Capital Trust I* 8.36% Trust Originated Preferred Securities (4,000,000 securities)**	$	—	$	100,000	$	25
HECO Capital Trust I* 8.05% Cumulative Quarterly Income Preferred Securities, Series 1997 (2,000,000 securities)**		—		50,000		25
HECO Capital Trust II* 7.30% Cumulative Quarterly Income Preferred Securities, Series 1998 (2,000,000 securities)**		—		50,000		25
HECO Capital Trust III* 6.50% Cumulative Quarterly Income Preferred Securities, Series 2004 (2,000,000 securities)***		50,000		—		25
	$	50,000	$	200,000

* Delaware grantor trust.

** Redeemed in April 2004 without premium.

*** Fully and unconditionally guaranteed by HECO; mandatorily redeemable at the maturity of the underlying debt on March 18, 2034, which maturity may be extended to no later than March 18, 2053; and redeemable at the issuer’s option without premium beginning on March 18, 2009.

On March 16, 2004, HEI completed the issuance and sale of 2 million shares of its common stock (pre-split) in a registered public offering. HEI used the net proceeds from the sale, along with other corporate funds, to effect the redemption of the Trust I 8.36% Trust Originated Preferred Securities in April 2004. Also in April 2004, the securities of the Partnership and HECO Capital Trusts I and II were redeemed. The Trust, the Partnership and HECO Capital Trusts I and II have been dissolved and are expected to be terminated in 2004 or early 2005.

(8) Retirement benefits

For the nine months ended September 30, 2004, the Company paid contributions of $25 million to the retirement benefit plans, compared to $18 million in the same period of 2003. The Company’s current estimate of contributions to the retirement benefit plans in 2004 is $27 million, compared to contributions of $48 million in 2003.

The components of net periodic benefit cost were as follows:

	Three months ended September 30												Nine months ended September 30
	Pension benefits						Other benefits						Pension benefits						Other benefits
(in thousands)	2004			2003			2004			2003			2004			2003			2004			2003
Service cost	$	6,677		$	5,609		$	1,133		$	916		$	19,778		$	17,254		$	3,398		$	2,664
Interest cost		12,662			12,023			2,693			2,632			37,993			35,904			8,078			7,777
Expected return on plan assets		(18,209	)		(14,943	)		(2,423	)		(1,909	)		(54,672	)		(44,643	)		(7,268	)		(5,730	)
Amortization of unrecognized transition obligation		1			238			785			819			3			715			2,354			2,458
Amortization of prior service cost (gain)		(145	)		(154	)		3			3			(442	)		(461	)		10			10
Recognized actuarial loss		284			1,116			—			—			876			2,866			—			—
Net periodic benefit cost	$	1,270		$	3,889		$	2,191		$	2,461		$	3,536		$	11,635		$	6,572		$	7,179

Of the net periodic benefit costs, the Company recorded expense of $8 million and $15 million in the first nine months of 2004 and 2003, respectively, and charged the remaining amounts primarily to electric utility plant.

In July 2004, the Company’s Pension Investment Committee approved a new target weighted-average asset allocation of pension and other postretirement benefit defined benefit plans as follows: equity securities—70% (previously 74%) and debt securities—30% (previously 25% and 1% of “other”). A plan to move toward these targets is being developed and is expected to be approved by the Pension Investment Committee by December 31, 2004.

11

(9) Common stock split

On April 20, 2004, the HEI Board of Directors approved a 2-for-1 stock split in the form of a 100% stock dividend with a record date of May 10, 2004 and a distribution date of June 10, 2004. All share and per share information in the accompanying financial statements, notes and elsewhere in this Form 10-Q have been adjusted to reflect the stock split for all periods presented (unless otherwise noted).

(10) Commitments and contingencies

See note 4, “Bank subsidiary,” and note 5, “Discontinued operations,” above and note 5, “Commitments and contingencies,” in HECO’s “Notes to Consolidated Financial Statements.”

(11) Cash flows

Supplemental disclosures of cash flow information

For the nine months ended September 30, 2004 and 2003, the Company paid interest amounting to $116.6 million and $130.3 million, respectively.

For the nine months ended September 30, 2004 and 2003, the Company paid income taxes amounting to $5.2 million and $13.7 million, respectively. In the second quarter of 2004, ASB expensed a $17 million deposit related to bank franchise taxes (see note 4 under “ASB Realty Corporation”). The $17 million is not included in cash income taxes paid in either 2003 or 2004 because it was paid as a deposit in 2003 and reclassified to income tax and other general and administrative expenses (interest portion) in 2004.

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 $4.5 million and $13.0 million for the nine months ended September 30, 2004 and 2003, respectively. Beginning in March 2004, HEI began satisfying the requirements of the HEI DRIP and the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) by acquiring for cash its common shares through open market purchases rather than the issuance of additional shares.

Other noncash increases in common stock for director and officer compensatory plans were $2.4 million and $3.6 million for the nine months ended September 30, 2004 and 2003, respectively.

(12) Recent accounting pronouncements and interpretations

Consolidation of variable interest entities (VIEs)

In January 2003, the FASB issued FIN 46, “Consolidation of Variable Interest Entities,” which addresses the consolidation of VIEs as defined. The Company was required to apply FIN 46 immediately to variable interests in VIEs created after January 31, 2003. For variable interests in VIEs created before February 1, 2003, FIN 46 was to be applied no later than the end of the first reporting period ending after December 15, 2003. The Company adopted the provisions (other than the already adopted disclosure provisions) of FIN 46 relating to VIEs created before February 1, 2003 as of December 31, 2003 with no effect on the Company’s financial statements.

In December 2003, the FASB issued revised FIN 46 (FIN 46R), “Consolidation of Variable Interest Entities,” which addresses how a business enterprise should evaluate whether it has a controlling financial interest in an entity through means other than voting rights and accordingly should consolidate the entity. FIN 46R replaced FIN 46. In the first quarter of 2004, the Company adopted the provisions of FIN 46R and deconsolidated Hawaiian Electric Industries Capital Trust I, HEI Preferred Funding, LP, HECO Capital Trust I and HECO Capital Trust II from their consolidated financial statements for the period ended, and as of, March 31, 2004. The Company did not elect to restate previously issued financial statements. See note 7 for additional information. Also, see note 7 of HECO’s “Notes to Consolidated Financial Statements” for a discussion of the application of FIN 46R to the electric utilities’ purchase power agreements (PPAs).

12

Amendment of SFAS No. 133

In April 2003, the FASB issued Statement of Financial Accounting Standards (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.

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 non-deferred 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 Emerging Issues Task Force (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 power purchase agreements for energy and 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 classification of the agreement 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. See note 7 of HECO’s “Notes to Consolidated Financial Statements” for a discussion of the application of EITF Issue No. 01-8 to the electric utilities’ PPAs.

Investments in other than common stock

In July 2004, the FASB ratified EITF Issue No. 02-14, “Whether an Investor Should Apply the Equity Method of Accounting to Investments Other Than Common Stock If the Investor Has the Ability to Exercise Significant Influence Over the Operating and Financial Policies of the Investee.” EITF Issue No. 02-14 requires that companies that have the ability to exercise significant influence over the investee apply the equity method of accounting when it has either common stock or “in-substance” common stock of a corporation. EITF Issue No. 02-14 will be effective in reporting periods beginning after September 15, 2004. The Company adopted EITF Issue No. 02-14 on October 1, 2004 and the adoption had no effect on the Company’s financial statements.

13

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

In March 2004, the FASB ratified EITF Issue No. 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments.” EITF Issue No. 03-1 provides guidance for determining whether an investment in debt or equity securities is impaired, evaluating whether an impairment is other-than-temporary and measuring impairment. EITF Issue No. 03-1 also provides disclosure guidance. The Company made the disclosures required by EITF Issue No. 03-1 for investments accounted for under SFAS No. 115 in its 2003 annual financial statements. Disclosure requirements for cost method investments are effective for fiscal years ending after June 15, 2004, and the Company will make such disclosures in its 2004 annual financial statements. The recognition and measurement guidance provided would be applied prospectively to all current and future investments within the scope of EITF Issue No. 03-1, originally effective in reporting periods beginning after June 15, 2004. In September 2004, the FASB issued FASB Staff Position (FSP) EITF 03-1-1 to delay the effective date of the recognition and measurement guidance. A new effective date is expected when the new guidance is issued.

Participating securities and the two-class method under SFAS No. 128

In March 2004, the FASB ratified EITF Issue No. 03-6, “Participating Securities and the Two-Class Method under FASB Statement No. 128.” EITF Issue No. 03-6 addresses various questions related to calculating earnings per share (EPS) in accordance with FASB Statement No. 128, “Earnings per Share,” including questions related to: (a) the types of securities that should be considered participating, (b) the application of the two-class method, and (c) the allocation of undistributed earnings and losses to participating securities. EITF No. 03-6 is effective for reporting periods beginning after March 31, 2004 and, if its application results in different EPS for prior periods, the previously-reported EPS should be restated. The Company adopted EITF Issue No. 03-6 in the second quarter of 2004 and the adoption had no effect on the Company’s financial statements.

Investments in limited liability companies

In March 2004, the FASB ratified EITF Issue No. 03-16, “Accounting for Investments in Limited Liability Companies.” EITF Issue No. 03-16 requires that an investment in a limited liability company (LLC) that maintains a “specific ownership account” for each investor (similar to a partnership capital account structure) to be viewed as similar to an investment in a limited partnership for purposes of determining whether a noncontrolling investment in an LLC should be accounted for using the cost method or equity method of accounting. EITF No. 03-16 was effective for reporting periods beginning after June 15, 2004. The Company adopted EITF Issue No. 03-16 on July 1, 2004 and the adoption had no effect on the Company’s financial statements.

Medicare Prescription Drug, Improvement and Modernization Act of 2003

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 was signed into law on December 8, 2003. The Act expanded Medicare to include for the first time coverage for prescription drugs. The Act provides that persons eligible for Medicare benefits can enroll in Part D, prescription drug coverage, for a monthly premium. Alternatively, if an employer sponsors a retiree health plan that provides benefits determined to be actuarially equivalent to those covered under the Medicare standard prescription drug benefit, the employer will be paid a subsidy of 28 percent of a participant’s drug costs between $250 and $5,000 if the participant does not elect to be covered under Medicare Part D.

In May 2004, the FASB issued FSP No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” When an employer is able to determine that benefits provided by its plan are actuarially equivalent to the Medicare Part D benefits, the FSP requires (a) treatment of the effects of the federal subsidy as an actuarial gain like similar gains and losses, and (b) certain financial statement disclosures related to the impact of the Act for employers that sponsor postretirement health care plans providing prescription drug benefits. The FASB’s related initial guidance, FSP No. 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” was superseded upon the effective date of FSP No. 106-2, which was the first interim or annual period beginning after June 15, 2004.

In the Company’s current disclosure, the accumulated postretirement benefit obligation and net periodic postretirement benefit cost do not reflect any amount associated with the federal subsidy because the Company is

14

unable to conclude whether the benefits it provides are actuarially equivalent to Medicare Part D benefits under the Act. Currently there is no guidance on how actuarial equivalence is to be determined. Should the federal subsidy apply, the Company expects the impact on costs associated with the subsidy to be immaterial.

The new Medicare legislation could impact the Company’s measures of accumulated postretirement benefit obligation and net periodic postretirement benefit cost in two ways: (1) as described above, the subsidy would reduce the obligation for benefits provided by the postretirement health plan, and (2) to the extent election into Medicare Part D coverage causes retirees to elect out of the Company’s plan, such measures will be lower. The Company does expect that fewer retirees will opt for drug coverage in the future because (1) the premiums retirees pay to participate in the plan has increased substantially, and (2) retirees may opt for coverage under Medicare Part D instead of the Company’s plan. The Company’s measures of accumulated postretirement benefit obligation and net periodic postretirement benefit cost reflect lower participation rates than in prior years, based on a study of current participation. The measures are expected to decrease in the future if experience unfolds showing further evidence of lower participation rates.

(13) Sale of income notes

In August 2004, HEI sold its investments in income notes (CDOs), which had been acquired by HEI from ASB in 2001, for proceeds of $9.3 million and a net after-tax gain of $3.6 million.

15

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated balance sheets (unaudited)

(in thousands, except par value)	September 30, 2004			December 31, 2003
Assets
Utility plant, at cost
Land	$	30,371		$	29,627
Plant and equipment		3,466,618			3,306,128
Less accumulated depreciation		(1,356,635	)		(1,290,929	)
Plant acquisition adjustment, net		210			249
Construction in progress		162,492			195,295
Net utility plant		2,303,056			2,240,370
Current assets
Cash and equivalents		6,730			158
Customer accounts receivable, net		108,115			91,999
Accrued unbilled revenues, net		68,534			60,372
Other accounts receivable, net		2,234			2,333
Fuel oil stock, at average cost		57,665			43,612
Materials and supplies, at average cost		24,122			21,233
Prepayments and other		103,942			86,763
Total current assets		371,342			306,470
Other long-term assets
Unamortized debt expense		14,900			14,035
Other		20,025			20,381
Total other long-term assets		34,925			34,416
	$	2,709,323		$	2,581,256
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		298,938			295,841
Retained earnings		619,535			563,215
Common stock equity		1,003,860			944,443
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
Long-term debt, net		752,108			699,420
Total capitalization		1,790,261			1,778,156
Current liabilities
Short-term borrowings—nonaffiliate		8,392			—
Short-term borrowings—affiliate		47,580			6,000
Accounts payable		85,784			72,377
Interest and preferred dividends payable		15,409			11,303
Taxes accrued		109,888			93,303
Other		35,268			34,015
Total current liabilities		302,321			216,998
Deferred credits and other liabilities
Deferred income taxes		185,028			170,841
Regulatory liabilities, net		82,595			71,882
Unamortized tax credits		52,147			47,066
Other		65,853			62,344
Total deferred credits and other liabilities		385,623			352,133
Contributions in aid of construction		231,118			233,969
	$	2,709,323		$	2,581,256

See accompanying notes to HECO’s Consolidated Financial Statements.

16

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated statements of income (unaudited)

	Three months ended September 30,						Nine months ended September 30,
(in thousands, except for ratio of earnings to fixed charges)	2004			2003			2004			2003
Operating revenues	$	408,766		$	358,435		$	1,124,103		$	1,039,781
Operating expenses
Fuel oil		128,584			101,296			340,166			294,303
Purchased power		105,985			92,543			292,491			273,161
Other operation		39,151			37,760			110,297			114,604
Maintenance		17,219			18,025			50,125			47,783
Depreciation		28,586			27,625			86,074			82,870
Taxes, other than income taxes		37,588			33,636			104,670			97,523
Income taxes		16,788			13,974			43,454			36,865
		373,901			324,859			1,027,277			947,109
Operating income		34,865			33,576			96,826			92,672
Other income
Allowance for equity funds used during construction		1,934			1,098			5,056			3,075
Other, net		1,157			(889	)		2,886			747
		3,091			209			7,942			3,822
Income before interest and other charges		37,956			33,785			104,768			96,494
Interest and other charges
Interest on long-term debt		10,821			9,973			31,716			30,733
Amortization of net bond premium and expense		578			579			1,724			1,620
Preferred securities distributions of trust subsidiaries		—			1,918			—			5,756
Other interest charges		743			953			4,135			1,702
Allowance for borrowed funds used during construction		(859	)		(496	)		(2,236	)		(1,385	)
Preferred stock dividends of subsidiaries		228			228			686			686
		11,511			13,155			36,025			39,112
Income before preferred stock dividends of HECO		26,445			20,630			68,743			57,382
Preferred stock dividends of HECO		270			270			810			810
Net income for common stock	$	26,175		$	20,360		$	67,933		$	56,572
Ratio of earnings to fixed charges (SEC method)								3.79			3.23

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated statements of retained earnings (unaudited)

	Three months ended September 30,					Nine months ended September 30,
(in thousands)	2004		2003			2004			2003
Retained earnings, beginning of period	$	593,360	$	549,703		$	563,215		$	542,023
Net income for common stock		26,175		20,360			67,933			56,572
Common stock dividends		—		(13,917	)		(11,613	)		(42,449	)
Retained earnings, end of period	$	619,535	$	556,146		$	619,535		$	556,146

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.

17

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated statements of cash flows (unaudited)

Nine months ended September 30	2004			2003
(in thousands)
Cash flows from operating activities
Income before preferred stock dividends of HECO	$	68,743		$	57,382
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities
Depreciation of property, plant and equipment		86,074			82,870
Other amortization		6,639			6,216
Deferred income taxes		16,619			3,795
Tax credits, net		3,790			1,197
Allowance for equity funds used during construction		(5,056	)		(3,075	)
Changes in assets and liabilities
Increase in accounts receivable		(16,017	)		(1,652	)
Decrease (increase) in accrued unbilled revenues		(8,162	)		417
Increase in fuel oil stock		(14,053	)		(2,676	)
Increase in materials and supplies		(2,889	)		(4,333	)
Increase in regulatory assets		(938	)		(2,266	)
Increase in accounts payable		13,407			1,856
Increase in taxes accrued		16,585			17,708
Changes in other assets and liabilities		(18,210	)		7,260
Net cash provided by operating activities		146,532			164,699
Cash flows from investing activities
Capital expenditures		(135,051	)		(83,550	)
Contributions in aid of construction		5,857			10,296
Other		1,951			—
Net cash used in investing activities		(127,243	)		(73,254	)
Cash flows from financing activities
Common stock dividends		(11,613	)		(42,449	)
Preferred stock dividends		(810	)		(810	)
Preferred securities distributions of trust subsidiaries		—			(5,756	)
Proceeds from issuance of long-term debt		52,525			67,360
Repayment of long-term debt		(103,092	)		(74,000	)
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		49,972			(5,600	)
Other		301			(4,535	)
Net cash used in financing activities		(12,717	)		(65,790	)
Net increase in cash and equivalents		6,572			25,655
Cash and equivalents, beginning of period		158			1,726
Cash and equivalents, end of period	$	6,730		$	27,381

See accompanying notes to HECO’s Consolidated Financial Statements.

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Hawaiian Electric Company, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) Basis of presentation

The accompanying unaudited consolidated financial statements have been prepared in conformity with GAAP for interim financial information 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/A for the year ended December 31, 2003 and the unaudited consolidated financial statements and the notes thereto in HECO’s Quarterly Reports on SEC Form 10-Q for the quarters ended March 31, 2004 and June 30, 2004.

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, 2004 and December 31, 2003 and the results of their operations for the three and nine months ended September 30, 2004 and 2003 and their cash flows for the nine months ended September 30, 2004 and 2003. 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) HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO and HECO-guaranteed debentures

Through December 31, 2003, HECO had included the financial statements of its subsidiary trusts, HECO Capital Trust I (Trust I) and HECO Capital Trust II (Trust II), in its consolidated financial statements, with the quarterly income preferred securities issued by those trusts being classified in HECO’s consolidated balance sheet under the heading “HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO and HECO-guaranteed debentures.”

In December 2003, the FASB issued FIN 46R, “Consolidation of Variable Interest Entities,” which addresses whether a business enterprise should consolidate an entity. HECO adopted the provisions of FIN 46R in the first quarter of 2004. Under FIN 46R, HECO deconsolidated both Trust I and Trust II and did not consolidate HECO Capital Trust III (Trust III), which issued preferred securities in the first quarter of 2004.

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Trust preferred securities issued by HECO’s unconsolidated (effective January 1, 2004) financing subsidiaries were as follows:

(in thousands, except per security amounts and number of securities)	September 30, 2004		December 31, 2003		Liquidation value per security
HECO Capital Trust I* 8.05% Cumulative Quarterly Income Preferred Securities, Series 1997 (2,000,000 securities)**	$	—	$	50,000	$	25
HECO Capital Trust II* 7.30% Cumulative Quarterly Income Preferred Securities, Series 1998 (2,000,000 securities)**		—		50,000		25
HECO Capital Trust III* 6.50% Cumulative Quarterly Income Preferred Securities, Series 2004 (2,000,000 securities)***		50,000		—		25
	$	50,000	$	100,000

* Delaware grantor trust and finance subsidiary of HECO.

** Redeemed in April 2004 without premium.

*** Fully and unconditionally guaranteed by HECO; mandatorily redeemable at the maturity of the underlying debt on March 18, 2034, which maturity may be extended to no later than March 18, 2053; and redeemable at the issuer’s option without premium beginning on March 18, 2009.

In March 2004, HECO, HELCO and MECO issued 6.50% Junior Subordinated Deferrable Interest Debentures, Series 2004 (2004 Debentures) to Trust III and, in April 2004, used the proceeds to cause the redemption of the 8.05% Cumulative Quarterly Income Preferred Securities, Series 1997, of Trust I. In April 2004, HECO and HELCO used funds primarily from short-term borrowings from HEI and from the issuance of commercial paper by HECO (and related short-term loans by HECO to HELCO), and MECO used funds temporarily invested with HECO to cause the redemption of the 7.30% Cumulative Quarterly Income Preferred Securities, Series 1998, of Trust II. Trust I and Trust II were dissolved in April 2004 and are expected to be terminated in 2004.

HECO Capital Trust III (Trust III) exists for the exclusive purposes of (i) issuing, in 2004, trust securities, consisting of 6.50% Cumulative Quarterly Income Preferred Securities, Series 2004 (2004 Trust Preferred Securities) ($50 million) issued to the public and trust common securities ($1.5 million) issued to HECO, (ii) investing the proceeds of the trust securities in 2004 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 2004 Trust Preferred Securities and trust common securities and (iv) engaging in only those other activities necessary or incidental thereto. The 2004 Debentures, together with the obligations of HECO, MECO and HELCO under an expense agreement and HECO’s obligations under its trust guarantee and its guarantee of the obligations of MECO and HELCO under their respective debentures, are the sole assets of Trust III. Trust III is an unconsolidated subsidiary of HECO. Trust III’s balance sheet as of September 30, 2004 consisted of $51.5 million of 2004 Debentures; $50.0 million of 2004 Trust Preferred Securities; and $1.5 million of common equity. Trust III’s income statement for the nine months ended September 30, 2004 consisted of $1.8 million of interest income received from the 2004 Debentures; $1.7 million of distributions to holders of the Trust Preferred Securities; and $54,000 of common dividends to HECO. So long as the 2004 Trust Preferred Securities are outstanding, HECO is not entitled to receive any funds from Trust III other than pro rata distributions on the common securities, and in certain circumstances, HECO’s right to receive such distributions is subordinate to the right of the holders to receive distributions on their 2004 Trust Preferred Securities. In the event of a default by HECO in the performance of its obligations under the 2004 Debentures or under its Guarantees, or in the event HECO, HELCO or MECO elect to defer payment of interest on any of their respective 2004 Debentures, HECO will be subject to a number of restrictions, including a prohibition on the payment of dividends on its common stock.

20

(3) Revenue taxes

HECO and its subsidiaries’ operating revenues include amounts for various revenue taxes. Revenue taxes are recorded as an expense in the period the related revenues are recognized. HECO and its subsidiaries payments to the taxing authorities are based on the prior year’s revenues. For the nine months ended September 30, 2004 and 2003, HECO and its subsidiaries included approximately $99 million and $92 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

(4) Retirement benefits

For the nine months ended September 30, 2004, HECO and its subsidiaries paid contributions of $22 million to the retirement benefit plans, compared to $15 million in the same period of 2003. HECO and its subsidiaries’ current estimate of contributions to the retirement benefit plans in 2004 is $24 million, compared to their contributions of $31 million in 2003.

The components of net periodic benefit cost were as follows:

	Three months ended September 30												Nine months ended September 30
	Pension benefits						Other benefits						Pension benefits						Other benefits
(in thousands)	2004			2003			2004			2003			2004			2003			2004			2003
Service cost	$	5,361		$	4,613		$	1,102		$	891		$	16,084		$	14,286		$	3,305		$	2,583
Interest cost		11,444			10,925			2,626			2,571			34,332			32,628			7,877			7,590
Expected return on plan assets		(16,670	)		(13,969	)		(2,388	)		(1,879	)		(50,011	)		(41,709	)		(7,165	)		(5,641	)
Amortization of unrecognized transition obligation		1			238			782			816			2			714			2,347			2,448
Amortization of prior service gain		(186	)		(188	)		—			—			(558	)		(563	)		—			—
Recognized actuarial loss		54			777			—			—			162			2,097			—			—
Net periodic benefit cost	$	4		$	2,396		$	2,122		$	2,399		$	11		$	7,453		$	6,364		$	6,980

Of the net periodic benefit costs, HECO and its subsidiaries recorded expense of $5 million and $10 million in the first nine months of 2004 and 2003, respectively, and charged the remaining amounts primarily to electric utility plant.

In July, 2004, the Company’s Pension Investment Committee approved a new target weighted-average asset allocation of pension and other postretirement benefit defined benefit plans as follows: equity securities—70% (previously 74%) and debt securities—30% (previously 25% and 1% of “other”). A plan to move toward these targets is being developed and is expected to be approved by the Pension Investment Committee by December 31, 2004.

(5) Commitments and contingencies

HELCO power situation

After several years of opposition to, and resulting delays in, the efforts of HELCO to expand its Keahole power plant site to add new generation, HELCO entered into a conditional settlement agreement in November of 2003 (Settlement Agreement) with all but one of the parties (Waimana Enterprises, Inc. (Waimana)), which had actively opposed the project, and with several regulatory agencies. The Settlement Agreement is intended to permit HELCO to complete the plant expansion, subject to satisfaction of the terms and conditions of the Settlement Agreement. Two nominal 20 megawatt (MW) combustion turbines (CT-4 and CT-5) have been installed and were put into limited commercial operation in May and June 2004, respectively. Under the Settlement Agreement, CT-4 and CT-5 must have noise mitigation measures installed before they can be operated full-time. The noise mitigation measures are expected to be installed by the end of 2004. To date, HELCO has reclassified $102 million of capital costs for CT-4, CT-5 and related pre-air permit facilities from construction in progress to plant and equipment of which $95 million was reclassified in 2004. HELCO’s electric rates, however, will not change specifically as a result of including CT-4 and CT-5 in HELCO’s plant and equipment until HELCO files a rate increase application and the PUC grants HELCO rate relief.

The following is a summary of the status of HELCO’s efforts to obtain certain of the permits required for the Keahole expansion project and related proceedings that have impeded and delayed HELCO’s efforts to construct the

21

plant, a description of the Settlement Agreement and its implementation to date and a discussion (under “Management’s evaluation; costs incurred”) of the potential financial statement implications of this project.

Historical context. In 1991, HELCO began planning to meet increased electric generation demand forecast for 1994. HELCO’s plans were to install at its Keahole power plant 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 in its decision 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) that had proposed generating facilities that they claimed would be a substitute for HELCO’s planned expansion of the Keahole plant, stating that the facility to be built should be the one that can be most expeditiously put into service at “allowable cost.”

Installation of CT-4 and CT-5 was significantly delayed, however, as a result of (a) delays in obtaining an amendment of a land use permit from the Hawaii Board of Land and Natural Resources (BLNR), which was required because the Keahole power plant is located in a conservation district, and a required air permit from the Department of Health of the State of Hawaii (DOH) and the U.S. Environmental Protection Agency (EPA) and (b) lawsuits and administrative proceedings initiated by IPPs and other parties contesting the grant of these permits and objecting to the expansion of the power plant on numerous grounds, including contentions that (i) operation of the expanded Keahole site would not comply with land use regulations (including noise standards) and the conditions of HELCO’s land patent; (ii) HELCO cannot operate the plant within current air quality standards; (iii) HELCO could alternatively purchase power from IPPs to meet increased electric generation demand; and (iv) HELCO’s land use entitlement expired in April 1999 because it had not completed the project within an alleged three-year construction deadline.

IPP complaints; related PPAs. Three IPPs—Kawaihae Cogeneration Partners (KCP), which is an affiliate of Waimana, Enserch Development Corporation (Enserch) and Hilo Coast Power Company (HCPC)—filed separate complaints with the PUC in 1993, 1994 and 1999, respectively, alleging that they were each entitled to a PPA to provide HELCO with additional capacity. KCP and Enserch each claimed that the generation capacity they would provide under their proposed PPAs would be a substitute for HELCO’s planned expansion of the Keahole plant.

The Enserch and HCPC complaints were resolved by HELCO’s entry into PPAs with each of these parties. The term of the PPA with Enserch is 30 years from December 31, 2000. The PPA with HCPC terminates in December 2004. HELCO believes that KCP’s proposal for a PPA is not viable.

Air permit. Following completion of all appeals from an air permit issued by the DOH in 1997 and then reissued in July 2001, a final air permit from the DOH became effective on November 27, 2001.

Land use permit amendment and related proceedings. The Third 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”). The Third Circuit Court’s 1998 final judgment on this issue was appealed to the Hawaii Supreme Court by several parties. On July 8, 2003, the Hawaii Supreme Court issued its opinion affirming the Third 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 the Hawaii Supreme Court’s July 2003 decision validated the Third Circuit Court’s 1998 final judgment confirming HELCO’s default entitlement, construction of the expansion project had been delayed for much of the intervening period that had followed the 1998 final judgment, first because HELCO had not yet obtained its final air permit and then because of other rulings made by the Third Circuit Court in several related proceedings.

The Third 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. Numerous proceedings were commenced before the Third Circuit Court and the BLNR in which parties opposed to the project claimed that HELCO had not or could not comply with the conditions applicable to its default entitlement. The Third Circuit Court issued a number of rulings in these

22

proceedings which further delayed or otherwise adversely affected HELCO’s ability to construct and efficiently operate CT-4 and CT-5. These rulings have now been, or are expected to be, resolved under the terms of the Settlement Agreement, as follows:

• Based on a change by the DOH in its interpretation of the noise rules it promulgated under the Hawaii Noise Pollution Act, the Third Circuit Court ruled that a stricter noise standard applied to HELCO’s Keahole plant. HELCO filed a separate complaint for declaratory relief against the DOH seeking the invalidation of the noise rules on constitutional and other grounds. The Third Circuit Court ruled against HELCO in that separate complaint, and HELCO appealed the Third Circuit Court’s final judgment to this effect (Noise Standards Judgment) in August 1999. In the Settlement Agreement, HELCO agrees that the Keahole plant will comply during normal operations with the stricter noise standards and that it will not begin full-time operations of CT-4 and CT-5 until it has installed noise mitigation equipment to meet these standards. In accordance with the Settlement Agreement, the parties filed a stipulation to dismiss HELCO’s appeal of the Noise Standards Judgment and the stipulation was approved in January 2004. HELCO is currently in the process of installing the contemplated noise mitigation measures.

• In other litigation in the Third Circuit Court brought by Keahole Defense Coalition (KDC) and two individuals (Individual Plaintiffs), the Third Circuit Court denied plaintiff’s motions made on several grounds to enjoin construction of the Keahole plant and plaintiffs appealed these rulings to the Hawaii Supreme Court in June 2002. Pursuant to the Settlement Agreement, KDC filed a motion in the Hawaii Supreme Court to dismiss this appeal and the motion was granted on April 12, 2004.

• In November 2000, the Third Circuit Court entered an order that, absent an extension authorized by the BLNR, the three-year construction period during which expansion of the Keahole plant should have been completed under the standard land use conditions of the Department of Land and Natural Resources of the State of Hawaii (DLNR) expired in April 1999. In December 2000, the Third Circuit Court granted a motion to stay further construction of the Keahole plant until an extension of the construction deadline was obtained. After an administrative hearing, in March 2002, the BLNR granted HELCO an extension of the construction deadline through December 31, 2003 (the March 2002 BLNR Order), subject to a number of conditions. In April 2002, based on the March 2002 BLNR Order, the Third Circuit Court lifted the stay it had imposed on construction and construction activities on CT-4 and CT-5 were restarted.

KDC and the Individual Plaintiffs appealed the March 2002 BLNR Order to the Third Circuit Court, as did the Department of Hawaiian Home Lands (DHHL). In September 2002, the Third Circuit Court issued a letter to the parties indicating its decision to reverse the March 2002 BLNR Order and the Third Circuit Court issued a final judgment to this effect in November 2002 (November 2002 Final Judgment). As a result of the letter ruling and November 2002 Final Judgment, the construction of CT-4 and CT-5 was once again suspended. HELCO appealed this ruling to the Hawaii Supreme Court.

The Settlement Agreement. With installation of CT-4 and CT-5 halted and the proceedings described above pending and unresolved, the parties that opposed the Keahole power plant expansion project (other than Waimana, which did not participate in the settlement discussions and opposes the settlement), including KDC, the Individual Plaintiffs and DHHL, engaged in a mediation process with HELCO and several Hawaii regulatory agencies in an attempt to achieve a resolution of the matters in dispute that would permit the project to be constructed and put in service. This process led to an agreement in principle ultimately embodied in the Settlement Agreement, executed by the last party to it on November 6, 2003, under which, subject to satisfaction of several conditions, HELCO would be permitted to proceed with installation of CT-4 and CT-5, and, in the future, ST-7. In addition to KDC, the Individual Plaintiffs, DHHL and HELCO, parties to the Settlement Agreement also include the DOH, the Director of the DOH, the DLNR and the BLNR.

In connection with efforts to implement the agreement in principle and Settlement Agreement:

• On October 10, 2003, the BLNR conditionally approved a 19-month extension of the previous December 31, 2003 construction deadline, but subject to court action allowing construction to proceed (BLNR 2003 Construction Period Extension).

23

• On October 14, 2003, the Hawaii Supreme Court granted a motion to remand the pending appeal of the November 2002 Final Judgment (which was halting construction) in order to permit the Third Circuit Court to consider a motion to vacate that judgment.

• On October 17, 2003, a motion to vacate the November 2002 Final Judgment was filed in the Third Circuit Court by KDC and DHHL.

• On November 12, 2003, the motion to vacate the November 2002 Final Judgment was granted by the Third Circuit Court, over Waimana’s objections, and, on November 28, 2003, the Third Circuit Court entered its first amended final judgment (November 2003 Final Judgment) vacating the November 2002 Final Judgment.

• On November 17, 2003, HELCO resumed construction of CT-4 and CT-5.

• On January 13, 2004, the Hawaii Supreme Court granted, over Waimana’s objection, HELCO’s motion to dismiss HELCO’s original appeal of the November 2002 Final Judgment (since that judgment had been vacated).

Full implementation of the Settlement Agreement is conditioned on obtaining final dispositions of all litigation and proceedings pending at the time the Settlement Agreement was entered into. While substantial progress continues to be made in achieving such dispositions, final dispositions of all such proceedings have not yet been obtained. If the remaining dispositions are obtained, as HELCO believes they will be, then HELCO has agreed in the Settlement Agreement that it will undertake a number of actions, in addition to complying with the stricter noise standards, to mitigate the impact of the power plant in terms of air pollution and potable water and aesthetic concerns. These actions relate to providing additional landscaping, expediting efforts to obtain the permits and approvals necessary for installation of ST-7 with selective catalytic reduction (SCR) emissions control equipment, operating existing CT-2 at Keahole within existing air permit limitations rather than the less stringent limitations in a pending air permit revision, using primarily 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, supporting KDC’s participation in certain PUC cases, paying legal expenses and other costs of various parties to the lawsuits and other proceedings, and cooperating with neighbors and community groups, including a Hot Line service for communications with neighboring DHHL beneficiaries.

Since the time construction activities resumed in November 2003, HELCO has begun implementation of many of its commitments under the Settlement Agreement. However, despite the numerous rulings against Waimana described above, Waimana has continued to pursue efforts to stop or delay the Keahole project and to interfere with implementation of the Settlement Agreement, including (a) filing a notice of appeal to the Hawaii Supreme Court of the Third Circuit Court’s November 2003 Final Judgment (vacating the November 2002 Final Judgment), (b) appealing to the Third Circuit Court the BLNR 2003 Construction Period Extension, (c) appealing to the Third Circuit Court the BLNR’s approval, on December 12, 2003, of HELCO’s request for a revocable permit to use brackish well water as the primary source of water for operating the Keahole plant and (d) along with a group representing DHHL beneficiaries, appealing to the Third Circuit Court the BLNR’s approval in March 2004 of HELCO’s request for a long-term water lease to use the brackish well water (subject to conditions including a public auction of qualified bidders, which occurred on July 1, 2004 with HELCO the sole and prevailing bidder). In January 2004, the Third Circuit Court denied Waimana’s motion to stay the effectiveness of the BLNR 2003 Construction Period Extension, and granted HELCO’s motion (joined in by the BLNR) to dismiss Waimana’s appeal of that extension. On April 15, 2004, Waimana appealed that ruling to the Supreme Court. In February 2004, the Third Circuit Court denied Waimana’s motion to stay the effectiveness of the revocable permit to use brackish water, and granted HELCO’s motion (joined in by the BLNR) to dismiss Waimana’s appeal of that permit. The final judgment was entered on April 7, 2004. Waimana appealed that judgment to the Supreme Court on April 22, 2004. With regard to the appeal of the water lease, which was fully executed in July 2004 and took effect on August 1, 2004, both Waimana and the other party filed motions to stay the effectiveness of the lease, which motions were denied. The appeal itself was heard on October 11, 2004, at which time the Court took the matter under advisement. The three Supreme Court appeals described in this paragraph, and the appeal to the Third Circuit Court described in (d) above, remain pending.

Land Use Commission petition. After previously submitting and withdrawing a petition, HELCO submitted to the Hawaii State Land Use Commission (LUC) on November 25, 2003 a new petition to reclassify the Keahole plant site from conservation land use to urban land use. The installation of ST-7, with SCR as contemplated by the Settlement

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Agreement, is dependent upon this reclassification. In December 2003, Waimana filed a Notice of Intent to Intervene in the LUC proceeding. On February 5, 2004, the LUC issued an order, with which HELCO concurred, that an environmental impact statement (EIS) be prepared in connection with the reclassification petition. Work on the EIS was already in progress before the ruling was issued. HELCO intends to file the draft EIS in the fourth quarter of 2004 and to request the LUC to consider it for approval in early 2005. The entire reclassification process could take several years.

Management’s evaluation; costs incurred. The probability that HELCO will be allowed to complete the installation of CT-4 and CT-5, including noise mitigation measures, during 2004 has been substantially enhanced by the Settlement Agreement, the Third Circuit’s November 2003 Final Judgment, and the decisions of the BLNR to extend the construction deadline by 19 months from December 31, 2003, to grant to HELCO a revocable permit to use brackish water for the plant and to grant HELCO’s request for a long-term lease of the brackish water. Although additional steps must be completed under the Settlement Agreement to satisfy its remaining conditions and HELCO must obtain the further permits necessary to allow full-time operation of CT-4 and CT-5 (and, eventually, to allow installation and operation of ST-7), management believes that the prospects are good that those conditions will be satisfied and that any further necessary permits will be obtained. Nevertheless, Waimana has continued its efforts to stop or delay the construction and there could be further delays in achieving full-time operation. Until such full-time operation is achieved, currently projected to occur by year-end, HELCO’s management remains concerned with 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 and fully operational, as well as the current operating status of various IPPs, which provide approximately 43% of HELCO’s generating capacity under power purchase agreements.

Based on management’s expectation that the remaining conditions under the Settlement Agreement will be satisfied, HELCO recorded, as expenses in November 2003, approximately $3.1 million of legal fees and other costs required to be paid under the Settlement Agreement. If the Settlement Agreement is implemented and ST-7 is installed, HELCO will have incurred approximately $24 million of capital expenditures relating to noise mitigation, visual mitigation and air pollution control at the Keahole power plant site (approximately $9 million for CT-4 and CT-5, approximately $10 million for ST-7, when installed, and approximately $5 million for other existing units). Other miscellaneous incidental expenses may also be incurred.

As of September 30, 2004, HELCO’s capitalized 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 $98 million, including $36 million for equipment and material purchases, $42 million for planning, engineering, permitting, site development and other costs and $20 million for an allowance for funds used during construction (AFUDC) up to November 30, 1998, after which date management decided not to continue to accrue AFUDC in light of the delays that had been experienced, even though management believes that it has acted prudently with respect to the Keahole project. As of September 30, 2004, estimated additional capital costs of approximately $8 million will be required to complete the installations of CT-4 and CT-5, including the costs necessary to satisfy the requirements of the Settlement Agreement pertaining to those units. To date, HELCO has reclassified $95 million of capital costs for CT-4, CT-5 (excluding related pre-air permit facilities) from construction in progress to plant and equipment and depreciation will be recorded beginning in January 2005. HELCO’s electric rates, however, will not change specifically as a result of including CT-4 and CT-5 in HELCO’s plant and equipment until HELCO files a rate increase application and the PUC grants HELCO rate relief.

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, 2004. 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.

HELCO’s plans for ST-7 are pending until it obtains the contemplated reclassification of the Keahole plant site from conservation to urban and obtain the necessary permits, which HELCO has agreed to seek promptly. The costs of ST-7 will be higher than originally planned, not only by reason of the change in schedule in its installation, but also by reason of additional costs that will be incurred to satisfy the requirements of the Settlement Agreement.

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East Oahu transmission system

HECO’s power sources are located primarily in West Oahu, but the bulk of HECO’s system load is in the Honolulu/East Oahu area. Accordingly, HECO transmits bulk power to the Honolulu/East Oahu area over two major transmission corridors (Northern and Southern). HECO had 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 proposed transmission line in its originally proposed location required the BLNR to approve a Conservation District Use Permit (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 and, in June 2002, the BLNR denied HECO’s request for a CDUP.

HECO continues to believe that the proposed project (the East Oahu Transmission Project) is needed to improve the reliability of the Pukele substation, which serves approximately 16% of Oahu’s electrical load, including Waikiki, and to address future potential line overloads under certain contingencies. In 2003, HECO completed its evaluation of alternative ways to accomplish the project (including using 46 kV transmission lines). As part of its evaluation, HECO conducted a community-based process to obtain public views of the alternatives. In December 2003, HECO filed an application with the PUC requesting approval to commit funds (currently estimated at $56 million, which amount includes $22 million of costs already incurred and disclosed below) for its revised East Oahu Transmission Project. In March 2004, the PUC granted intervenor status to an environmental organization and three elected officials, granted a more limited participant status to four community organizations, and denied intervention sought by two individuals in the PUC proceeding.

At HECO’s request, the PUC has agreed to be the accepting agency for an environmental assessment (EA) of HECO’s East Oahu Transmission Project to be voluntarily prepared by HECO. An EIS would be prepared if the PUC finds that the proposed action may have a significant effect on the environment. Public notice of the availability of the draft EA for the revised project was published in the Environmental Notice on September 8, 2004, the date from which the public had 30 days to comment on the draft EA. The PUC conducted a public hearing on September 1, 2004 for the proposed project. Under a stipulated order modified and adopted by the PUC in May 2004, the testimonies of the other parties and the evidentiary hearing before the PUC are scheduled to follow the completion of an environmental review process. That process will be deemed to be complete when the PUC reviews the final EA, which must incorporate and respond to all public comments received on the draft EA, and either determines that an EIS is not required or, if an EIS is required, when the final EIS is accepted.

Subject to PUC approval, the revised project, none of which is in conservation district lands, will be built in two phases. Completion of the first phase, currently projected for 2007, 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 that could occur under certain contingencies.

On March 3, 2004, approximately 40,000 of HECO’s customers in the Honolulu/East Oahu area, including Waikiki, lost power. The Pukele substation serves the affected areas. One of the two transmission lines serving the Pukele substation was out for scheduled maintenance when the second transmission line went out of service and resulted in the power outage. Management believes that the sustained outage would have been prevented if the East Oahu Transmission Project had been completed. Many of the customers affected on March 3, 2004 would not have seen any interruption in service, while the other affected customers would have experienced a momentary interruption of service lasting only seconds.

As of September 30, 2004, the accumulated costs related to the East Oahu Transmission Project amounted to $22 million, including $14 million for planning, engineering and permitting costs and $8 million for AFUDC. These costs are recorded in construction in progress. 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, 2004. 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.

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

In April 2002, HECO and HEI were served with an amended complaint filed in the 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 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.

The amended PPA, which has a 30-year term, was approved by the PUC in December 1989, following contested case hearings in October 1988 and November 1989. The PUC proceedings addressed a number of issues, including 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.

In December 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. 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.

In March 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, and ruled that the case would be dismissed if plaintiffs failed to provide proof of having initiated an appropriate PUC proceeding by then. No such PUC proceeding was initiated.

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. Final briefing of the issues on the appeal and cross-appeal was completed in May 2004. By order filed on July 16, 2004, the Supreme Court retained jurisdiction of the appeal (rather than assign it to the Intermediate Court of Appeals for disposition). In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Company’s consolidated financial position, results of operations or liquidity.

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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 1995, the DOH issued letters indicating that it had identified a number of parties, including HECO, Hawaiian Tug & Barge Corp. (HTB) and Young Brothers, Limited (YB), who appear to be potentially responsible for the contamination and/or operated their facilities upon contaminated land at or near Honolulu Harbor. Certain of the identified parties formed a work group, which entered into a voluntary agreement with the DOH to determine the nature and extent of any contamination, the potentially responsible parties and appropriate remedial actions. The work group submitted reports and recommendations to the DOH and engaged a consultant who identified 27 additional potentially responsible parties (PRPs). The EPA became involved in the investigation in June 2000. Later in 2000, the DOH issued notices to additional PRPs. A new voluntary agreement and a joint defense agreement were signed by the parties in the work group and some of the new PRPs, which parties are known as the Iwilei District Participating Parties (Participating Parties). The Participating Parties agreed to fund remediation work using an interim cost allocation method (subject to a final allocation) and have organized a limited liability company to perform the work.

Under the terms of the 1999 agreement for the sale of assets of HTB and the stock 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 April 2003, TOOTS agreed to pay $250,000 (for TOOTS and HEI) to the Participating Parties to fund response activities in the Iwilei Unit of the Honolulu Harbor site, as a one-time cash-out payment in lieu of continuing with further response activities.

Since 2001, subsurface investigation and assessment has been conducted and several preliminary oil removal tasks have been performed at the Iwilei Unit in accordance with notices of interest issued by the EPA. Currently, the Participating Parties are preparing a Remediation Alternatives Analysis which will identify and recommend remedial technologies and will further analyze the anticipated costs to be incurred.

In addition to routinely maintaining its facilities, HECO had previously investigated its operations and ascertained that they were not releasing petroleum in the Iwilei Unit. In October 2002, HECO and three other companies (the Operating Companies) entered into a voluntary agreement with the DOH to evaluate their facilities to determine whether they are currently releasing petroleum to the subsurface in the Iwilei Unit. Pursuant to the agreement, the Operating Companies retained an independent consultant to conduct the evaluation. Based on available data, its own evaluation, as well as comments by the EPA, DOH and Operating Companies, the independent consultant issued a final report in the fourth quarter of 2003 that confirmed that HECO’s facilities in the Iwilei Unit are functioning properly, not leaking, operating in compliance with all regulatory requirements and not contributing to contamination in the Iwilei District. In view of the final report, HECO does not anticipate that further work will be necessary under the 2002 voluntary agreement.

Management developed a preliminary estimate of HECO’s share of costs primarily from 2002 through 2005 for continuing investigative work, remedial activities and monitoring at the Iwilei Unit of approximately $1.1 million (of which $0.4 million has been incurred through November 1, 2004). The $1.1 million estimate was expensed in 2001. Also, individual companies have incurred costs to remediate their facilities which will not be allocated to the Participating Parties. 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.

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Maalaea Units 12 and 13 notice and finding of violation. On September 5, 2003, 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. 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, unless MECO submitted a written request for a hearing. In September 2003, MECO submitted a request for hearing and accrued $1.6 million for the potential penalty. An environmental penalty or a settlement of an environmental penalty is not tax deductible.

In December 2003, the DOH and MECO reached a conditional settlement of the NOV (reducing the penalty to approximately $0.8 million) and MECO reduced the initial September 2003 accrual of $1.6 million to $0.8 million. In late March 2004, after a public notice and comment period, the Consent Order was formally signed and approved by both the DOH and MECO, and MECO paid the fine of approximately $0.8 million. The Consent Order also requires MECO to come into full compliance with the opacity rules for the units by December 31, 2004 (and MECO was in compliance at September 30, 2004). The Consent Order resolves all civil liability of MECO to the DOH for all opacity violations from February 1, 1999 to December 31, 2004.

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 electric utilities’ approximately 1,860 employees, about 1,100 are members of IBEW, AFL-CIO, Local 1260, Unit 8, which is the only union representing employees of the Company. 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.

(6) Cash flows

Supplemental disclosures of cash flow information

For the nine months ended September 30, 2004 and 2003, HECO and its subsidiaries paid interest amounting to $30.1 million and $26.1 million, respectively.

For the nine months ended September 30, 2004 and 2003, HECO and its subsidiaries paid income taxes amounting to $6.5 million and $15.7 million, respectively.

Supplemental disclosure of noncash activities

The allowance for equity funds used during construction, which was charged to construction in progress as part of the cost of electric utility plant, amounted to $5.1 million and $3.1 million for the nine months ended September 30, 2004 and 2003, respectively.

(7) Recent accounting pronouncements and interpretations

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. HECO and its subsidiaries were required to apply FIN 46 immediately to variable interests in VIEs created after January 31, 2003. For variable interests in VIEs created before February 1, 2003, FIN 46 was to be applied no later than the end of the first reporting period ending after December 15, 2003. HECO and subsidiaries adopted the provisions (other than the already adopted disclosure provisions) of FIN 46 relating to VIEs created before February 1, 2003 as of December 31, 2003 with no effect on consolidated HECO’s financial statements.

In December 2003, the FASB issued FIN 46R, “Consolidation of Variable Interest Entities,” which addresses how a business enterprise should evaluate whether it has a controlling financial interest in an entity through means other than voting rights and accordingly should consolidate the entity. FIN 46R replaced FIN 46. In the first quarter of 2004, HECO and its subsidiaries adopted the provisions of FIN 46R and deconsolidated HECO Capital Trust I and HECO Capital Trust II from their consolidated financial statements for the period ended, and as of, March 31, 2004. HECO

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and its subsidiaries did not elect to restate previously issued financial statements. See note 2 for additional information.

As of September 30, 2004, HECO and its subsidiaries had seven PPAs for a total of 534 MW of firm capacity, and other PPAs with smaller IPPs and Schedule Q providers that supplied as-available energy. Approximately 87% of the 534 MW of firm capacity is under PPAs, entered into before December 31, 2003, with AES Hawaii, Kalaeloa Partners, L.P. (Kalaeloa), Hamakua Energy Partners, L.P. (Hamakua) and H-POWER. Purchases from all IPPs for the nine months ended September 30, 2004 totaled $292 million, with purchases from AES Hawaii, Kalaeloa, Hamakua and H-POWER totaling $99 million, $96 million, $37 million and $22 million, respectively. The primary business activities of these IPPs are the generation and sale of power to HECO and its subsidiaries. Current financial information about the size, including total assets and revenues, for many of these IPPs is not publicly available. Under FIN 46R, an enterprise with an interest in a VIE or potential VIE created before December 31, 2003 is not required to apply FIN 46R to that entity if the enterprise is unable to obtain, after making an exhaustive effort, the information necessary to (1) determine whether the entity is a VIE, (2) determine whether the enterprise is the VIE’s primary beneficiary, or (3) perform the accounting required to consolidate the VIE for which it is determined to be the primary beneficiary.

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

In October 2004, Kalaeloa and HECO executed two amendments to their PPA under which, if PUC approval is obtained and other conditions are satisfied, Kalaeloa may make an additional 29 MW of firm capacity available to HECO. Under the first amendment, Kalaeloa agrees to make available to HECO the information HECO needs to (1) determine if HECO must consolidate Kalaeloa under the provisions of FIN 46R, (2) consolidate Kalaeloa if necessary, and (3) comply with Section 404 of the Sarbanes-Oxley Act of 2002. The agreement to make information available is subject to the issuance by the PUC of an acceptable order which, among other things, approves the amendment and orders that HECO may recover the costs resulting from the amendments in HECO’s electric rates.

As required under FIN 46R, HECO and its subsidiaries will continue their efforts to obtain the information necessary to make the determinations required under FIN 46R. If the requested information is ultimately received, a possible outcome of future analyses is the consolidation of an IPP in HECO’s consolidated financial statements. The consolidation of any significant IPP would have a material effect on HECO’s consolidated financial statements, including the recognition of a significant amount of assets and liabilities, and, if such a consolidated IPP were operating at a loss, the potential recognition of such losses.

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 non-deferred provisions

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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 power purchase agreements for energy and 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 PPA 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 classification of the agreement 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.

In October 2004, Kalaeloa and HECO executed two amendments to their PPA. HECO reassessed the PPA under EITF Issue No. 01-8 due to the amendments and determined that the PPA does not contain a lease because HECO does not control or operate Kalaeloa’s property, plant or equipment and another party is purchasing more than a minor amount of the output.

Medicare Prescription Drug, Improvement and Modernization Act of 2003

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 was signed into law on December 8, 2003. The Act expanded Medicare to include for the first time coverage for prescription drugs. The Act provides that persons eligible for Medicare benefits can enroll in Part D, prescription drug coverage, for a monthly premium. Alternatively, if an employer sponsors a retiree health plan that provides benefits determined to be actuarially equivalent to those covered under the Medicare standard prescription drug benefit, the employer will be paid a subsidy of 28 percent of a participant’s drug costs between $250 and $5,000 if the participant does not elect to be covered under Medicare Part D.

In May 2004, the FASB issued FSP No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” When an employer is able to determine that benefits provided by its plan are actuarially equivalent to the Medicare Part D benefits, the FSP requires (a) treatment of the effects of the federal subsidy as an actuarial gain like similar gains and losses, and (b) certain financial statement disclosures related to the impact of the Act for employers that sponsor postretirement health care plans providing prescription drug benefits. The FASB’s related initial guidance, FSP No. 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” was superseded upon the effective date of FSP No. 106-2, which was the first interim or annual period beginning after June 15, 2004.

In HECO and its subsidiaries’ current disclosure, the accumulated postretirement benefit obligation and net periodic postretirement benefit cost do not reflect any amount associated with the federal subsidy because HECO and its subsidiaries are unable to conclude whether the benefits it provides are actuarially equivalent to Medicare Part D benefits under the Act. Currently there is no guidance on how actuarial equivalence is to be determined. Should the federal subsidy apply, HECO and its subsidiaries expect the impact on costs associated with the subsidy to be immaterial.

The new Medicare legislation could impact HECO consolidated’s measures of accumulated postretirement benefit obligation and net periodic postretirement benefit cost in two ways: (1) as described above, the subsidy would reduce the obligation for benefits provided by the postretirement health plan, and (2) to the extent election into Medicare Part D coverage causes retirees to elect out of HECO consolidated’s plan, such measures will be lower. HECO and its subsidiaries do expect that fewer retirees will opt for drug coverage in the future because (1) the premiums retirees pay to participate in the plan has increased substantially, and (2) retirees may opt for coverage under Medicare Part D instead of HECO consolidated’s plan. HECO consolidated’s measures of accumulated postretirement benefit obligation and net periodic postretirement benefit cost reflect lower participation rates than in

31

prior years, based on a study of current participation. The measures are expected to decrease in the future if experience unfolds showing further evidence of lower participation rates.

(8) Repairs and maintenance costs

HECO and its utility subsidiaries’ policy is to expense repairs and maintenance costs for planned major maintenance overhauls of its generating units as they are incurred.

(9) 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)	2004			2003			2004			2003
Operating income from regulated and nonregulated activities before income taxes (per HEI consolidated statements of income)	$	52,713		$	46,636		$	142,767		$	130,196
Deduct:
Income taxes on regulated activities		(16,788	)		(13,974	)		(43,454	)		(36,865	)
Revenues from nonregulated activities		(1,310	)		(815	)		(3,191	)		(2,910	)
Add:
Expenses from nonregulated activities		250			1,729			704			2,251
Operating income from regulated activities after income taxes (per HECO consolidated statements of income)	$	34,865		$	33,576		$	96,826		$	92,672

(10) Consolidating financial information

HECO is not required to provide separate financial statements and other disclosures concerning HELCO and MECO to holders of the 2004 Debentures issued by HELCO and MECO since these securities have been fully and unconditionally guaranteed, on a subordinated basis, by HECO and consolidating information is provided below for these and other HECO subsidiaries for the periods ended and as of the dates indicated. HECO also unconditionally guarantees HELCO’s and MECO’s obligations (a) to the State of Hawaii for the repayment of principal and interest on their Special Purpose Revenue Bonds and (b) relating to the trust preferred securities of HECO Capital Trust III. Also, see note 2. 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.

32

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating balance sheet (unaudited)

September 30, 2004

(in thousands)	HECO			HELCO		MECO		RHI	Reclassifi- cations and eliminations		HECO consolidated
Assets
Utility plant, at cost
Land	$	23,035		3,019		4,317		—	—		$	30,371
Plant and equipment		2,128,138		700,113		638,367		—	—			3,466,618
Less accumulated depreciation		(851,817	)	(251,153	)	(253,665	)	—	—			(1,356,635	)
Plant acquisition adjustment, net		—		—		210		—	—			210
Construction in progress		134,907		17,885		9,700		—	—			162,492
Net utility plant		1,434,263		469,864		398,929		—	—			2,303,056
Investment in subsidiaries, at equity		383,969		—		—		—	(383,969	)		—
Current assets
Cash and equivalents		8		2,040		4,363		319	—			6,730
Advances to affiliates		28,000		—		24,000		—	(52,000	)		—
Customer accounts receivable, net		74,475		17,734		15,906		—	—			108,115
Accrued unbilled revenues, net		47,805		11,000		9,729		—	—			68,534
Other accounts receivable, net		1,669		925		387		—	(747	)		2,234
Fuel oil stock, at average cost		43,246		4,502		9,917		—	—			57,665
Materials and supplies, at average cost		11,633		2,936		9,553		—	—			24,122
Prepayments and other		82,483		14,027		7,432		—	—			103,942
Total current assets		289,319		53,164		81,287		319	(52,747	)		371,342
Other long-term assets
Unamortized debt expense		9,997		2,507		2,396		—	—			14,900
Other		14,217		4,024		1,784		—	—			20,025
Total other long-term assets		24,214		6,531		4,180		—	—			34,925
	$	2,131,765		529,559		484,396		319	(436,716	)	$	2,709,323
Capitalization and liabilities
Capitalization
Common stock equity	$	1,003,860		184,271		199,387		311	(383,969	)	$	1,003,860
Cumulative preferred stock—not subject to mandatory redemption		22,293		7,000		5,000		—	—			34,293
Long-term debt, net		467,445		130,897		153,766		—	—			752,108
Total capitalization		1,493,598		322,168		358,153		311	(383,969	)		1,790,261
Current liabilities
Short-term borrowings—nonaffiliates		8,392		—		—		—	—			8,392
Short-term borrowings—affiliate		71,580		28,000		—		—	(52,000	)		47,580
Accounts payable		64,685		13,774		7,325		—	—			85,784
Interest and preferred dividends payable		10,894		1,839		2,747		—	(71	)		15,409
Taxes accrued		69,836		18,041		22,011		—	—			109,888
Other		23,775		6,419		5,742		8	(676	)		35,268
Total current liabilities		249,162		68,073		37,825		8	(52,747	)		302,321
Deferred credits and other liabilities
Deferred income taxes		145,680		22,185		17,163		—	—			185,028
Regulatory liabilities, net		48,357		21,535		12,703		—	—			82,595
Unamortized tax credits		29,973		10,988		11,186		—	—			52,147
Other		23,259		29,131		13,463		—	—			65,853
Total deferred credits and other liabilities		247,269		83,839		54,515		—	—			385,623
Contributions in aid of construction		141,736		55,479		33,903		—	—			231,118
	$	2,131,765		529,559		484,396		319	(436,716	)	$	2,709,323

33

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating balance sheet (unaudited)

December 31, 2003

(in thousands)	HECO			HELCO		MECO		RHI	HECO Capital Trust I	HECO Capital Trust II	Reclassi- fications and eliminations		HECO consolidated
Assets
Utility plant, at cost
Land	$	23,010		3,017		3,600		—	—	—	—		$	29,627
Plant and equipment		2,086,383		589,360		630,385		—	—	—	—			3,306,128
Less accumulated depreciation		(814,699	)	(238,320	)	(237,910	)	—	—	—	—			(1,290,929	)
Plant acquisition adjustment, net		—		—		249		—	—	—	—			249
Construction in progress		93,450		95,879		5,966		—	—	—	—			195,295
Net utility plant		1,388,144		449,936		402,290		—	—	—	—			2,240,370
Investment in subsidiaries, at equity		364,973		—		—		—	—	—	(364,973	)		—
Current assets
Cash and equivalents		9		4		87		58	—	—	—			158
Advances to affiliates		10,800		—		25,500		—	51,546	51,546	(139,392	)		—
Customer accounts receivable, net		63,227		16,077		12,695		—	—	—	—			91,999
Accrued unbilled revenues, net		41,200		10,697		8,475		—	—	—	—			60,372
Other accounts receivable, net		2,030		754		443		—	—	—	(894	)		2,333
Fuel oil stock, at average cost		32,060		3,526		8,026		—	—	—	—			43,612
Materials and supplies, at average cost		10,331		2,536		8,366		—	—	—	—			21,233
Prepayments and other		69,051		11,621		6,091		—	—	—	—			86,763
Total current assets		228,708		45,215		69,683		58	51,546	51,546	(140,286	)		306,470
Other long-term assets
Unamortized debt expense		9,492		2,328		2,215		—	—	—	—			14,035
Other		14,658		3,366		2,357		—	—	—	—			20,381
Total other long-term assets		24,150		5,694		4,572		—	—	—	—			34,416
	$	2,005,975		500,845		476,545		58	51,546	51,546	(505,259	)	$	2,581,256
Capitalization and liabilities
Capitalization
Common stock equity	$	944,443		174,639		187,195		47	1,546	1,546	(364,973	)	$	944,443
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		497,915		140,868		163,729		—	—	—	(103,092	)		699,420
Total capitalization		1,464,651		322,507		355,924		47	51,546	51,546	(468,065	)		1,778,156
Current liabilities
Short-term borrowings—affiliate		31,500		10,800		—		—	—	—	(36,300	)		6,000
Accounts payable		49,423		10,593		12,361		—	—	—	—			72,377
Interest and preferred dividends payable		7,890		1,387		2,057		—	—	—	(31	)		11,303
Taxes accrued		58,562		16,523		18,218		—	—	—	—			93,303
Other		20,752		7,772		6,343		11	—	—	(863	)		34,015
Total current liabilities		168,127		47,075		38,979		11	—	—	(37,194	)		216,998
Deferred credits and other liabilities
Deferred income taxes		137,919		20,079		12,843		—	—	—	—			170,841
Regulatory liabilities, net		42,235		18,935		10,712		—	—	—	—			71,882
Unamortized tax credits		27,703		8,633		10,730		—	—	—	—			47,066
Other		21,525		27,341		13,478		—	—	—	—			62,344
Total deferred credits and other liabilities		229,382		74,988		47,763		—	—	—	—			352,133
Contributions in aid of construction		143,815		56,275		33,879		—	—	—	—			233,969
	$	2,005,975		500,845		476,545		58	51,546	51,546	(505,259	)	$	2,581,256

34

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating statement of income (unaudited)

Three months ended September 30, 2004

(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions			HECO consoli- dated
Operating revenues	$	276,476		63,783		68,507		—			—		$	408,766
Operating expenses
Fuel oil		87,062		10,420		31,102		—			—			128,584
Purchased power		78,874		23,838		3,273		—			—			105,985
Other operation		25,568		6,791		6,792		—			—			39,151
Maintenance		10,969		2,854		3,396		—			—			17,219
Depreciation		17,223		5,291		6,072		—			—			28,586
Taxes, other than income taxes		25,356		5,833		6,399		—			—			37,588
Income taxes		10,520		2,750		3,518		—			—			16,788
		255,572		57,777		60,552		—			—			373,901
Operating income		20,904		6,006		7,955		—			—			34,865
Other income
Allowance for equity funds used during construction		1,716		90		128		—			—			1,934
Equity in earnings of subsidiaries		9,510		—		—		—			(9,510	)		—
Other, net		1,260		30		51		(10	)		(174	)		1,157
		12,486		120		179		(10	)		(9,684	)		3,091
Income before interest and other charges		33,390		6,126		8,134		(10	)		(9,684	)		37,956
Interest and other charges
Interest on long-term debt		6,754		1,831		2,236		—			—			10,821
Amortization of net bond premium and expense		372		101		105		—			—			578
Other interest charges		585		241		91		—			(174	)		743
Allowance for borrowed funds used during construction		(766	)	(44	)	(49	)	—			—			(859	)
Preferred stock dividends of subsidiaries		—		—		—		—			228			228
		6,945		2,129		2,383		—			54			11,511
Income before preferred stock dividends of HECO		26,445		3,997		5,751		(10	)		(9,738	)		26,445
Preferred stock dividends of HECO		270		133		95		—			(228	)		270
Net income for common stock	$	26,175		3,864		5,656		(10	)	$	(9,510	)	$	26,175

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Retained Earnings (unaudited)

Three months ended September 30, 2004

(in thousands)	HECO		HELCO	MECO	RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Retained earnings, beginning of period	$	593,360	79,763	98,809	(160	)	(178,412	)	$	593,360
Net income for common stock		26,175	3,864	5,656	(10	)	(9,510	)		26,175
Common stock dividends		—	—	—	—		—			—
Retained earnings, end of period	$	619,535	83,627	104,465	(170	)	(187,922	)	$	619,535

35

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
Preferred securities distributions of trust subsidiaries		—		—		—		—		—	—	1,918			1,918
Other interest charges		1,916		538		567		—		—	—	(2,068	)		953
Allowance for borrowed funds used during construction		(420	)	(32	)	(44	)	—		—	—	—			(496	)
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

36

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating statement of income (unaudited)

Nine months ended September 30, 2004

(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Operating revenues	$	764,711		175,186		184,206		—		—		$	1,124,103
Operating expenses
Fuel oil		235,723		26,438		78,005		—		—			340,166
Purchased power		217,732		66,221		8,538		—		—			292,491
Other operation		73,727		17,562		19,008		—		—			110,297
Maintenance		30,585		9,557		9,983		—		—			50,125
Depreciation		51,984		15,873		18,217		—		—			86,074
Taxes, other than income taxes		71,117		16,323		17,230		—		—			104,670
Income taxes		26,706		6,726		10,022		—		—			43,454
		707,574		158,700		161,003		—		—			1,027,277
Operating income		57,137		16,486		23,203		—		—			96,826
Other income
Allowance for equity funds used during construction		4,500		222		334		—		—			5,056
Equity in earnings of subsidiaries		25,802		—		—		—		(25,802	)		—
Other, net		3,158		196		(72	)	(36	)	(360	)		2,886
		33,460		418		262		(36	)	(26,162	)		7,942
Income before interest and other charges		90,597		16,904		23,465		(36	)	(26,162	)		104,768
Interest and other charges
Interest on long-term debt		19,805		5,354		6,557		—		—			31,716
Amortization of net bond premium and expense		1,106		301		317		—		—			1,724
Other interest charges		2,942		890		663		—		(360	)		4,135
Allowance for borrowed funds used during construction		(1,999	)	(109	)	(128	)	—		—			(2,236	)
Preferred stock dividends of subsidiaries		—		—		—		—		686			686
		21,854		6,436		7,409		—		326			36,025
Income before preferred stock dividends of HECO		68,743		10,468		16,056		(36	)	(26,488	)		68,743
Preferred stock dividends of HECO		810		400		286		—		(686	)		810
Net income for common stock	$	67,933		10,068		15,770		(36	)	(25,802	)	$	67,933

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating statement of retained earnings (unaudited)

Nine months ended September 30, 2004

(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Retained earnings, beginning of period	$	563,215		74,629		92,909		(134	)	(167,404	)	$	563,215
Net income for common stock		67,933		10,068		15,770		(36	)	(25,802	)		67,933
Common stock dividends		(11,613	)	(1,070	)	(4,214	)	—		5,284			(11,613	)
Retained earnings, end of period	$	619,535		83,627		104,465		(170	)	(187,922	)	$	619,535

37

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
Preferred securities distributions of trust subsidiaries		—		—		—		—		—	—	5,756			5,756
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 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

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating statement of cash flows (unaudited)

Nine months ended September 30, 2004

(in thousands)	HECO			HELCO		MECO		RHI		Reclassifi- cations and eliminations		HECO consolidated
Cash flows from operating activities
Income before preferred stock dividends of HECO	$	68,743		10,468		16,056		(36	)	(26,488	)	$	68,743
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities
Equity in earnings		(25,962	)	—		—		—		25,802			(160	)
Common stock dividends received from subsidiaries		5,444		—		—		—		(5,284	)		160
Depreciation of property, plant and equipment		51,984		15,873		18,217		—		—			86,074
Other amortization		3,304		581		2,754		—		—			6,639
Deferred income taxes		9,172		2,563		4,884		—		—			16,619
Tax credits, net		1,652		2,062		76		—		—			3,790
Allowance for equity funds used during construction		(4,500	)	(222	)	(334	)	—		—			(5,056	)
Changes in assets and liabilities
Increase in accounts receivable		(10,887	)	(1,828	)	(3,155	)	—		(147	)		(16,017	)
Increase in accrued unbilled revenues		(6,605	)	(303	)	(1,254	)	—		—			(8,162	)
Increase in fuel oil stock		(11,186	)	(976	)	(1,891	)	—		—			(14,053	)
Increase in materials and supplies		(1,302	)	(400	)	(1,187	)	—		—			(2,889	)
Decrease (increase) in regulatory assets		210		587		(1,735	)	—		—			(938	)
Increase (decrease) in accounts payable		15,262		3,181		(5,036	)	—		—			13,407
Increase in taxes accrued		11,274		1,518		3,793		—		—			16,585
Changes in other assets and liabilities		(14,928	)	(2,071	)	(1,355	)	(3	)	147			(18,210	)
Net cash provided by (used in) operating activities		91,675		31,033		29,833		(39	)	(5,970	)		146,532
Cash flows from investing activities
Capital expenditures		(86,376	)	(34,923	)	(13,752	)	—		—			(135,051	)
Contributions in aid of construction		3,194		1,476		1,187		—		—			5,857
Proceeds from sale of property		404		—		—		—		—			404
Investment in subsidiary		(1,846	)	—		—		—		300			(1,546	)
Distributions from unconsolidated subsidiaries		3,093		—		—		—		—			3,093
Advances to (repayments from) affiliates		(17,200	)	—		1,500		—		15,700			—
Net cash provided by (used in) investing activities		(98,731	)	(33,447	)	(11,065	)	—		16,000			(127,243	)
Cash flows from financing activities
Common stock dividends		(11,613	)	(1,070	)	(4,214	)	—		5,284			(11,613	)
Preferred stock dividends		(810	)	(400	)	(286	)	—		686			(810	)
Proceeds from issuance of long-term debt		32,525		10,000		10,000		—		—			52,525
Repayment of long-term debt		(63,092	)	(20,000	)	(20,000	)	—		—			(103,092	)
Proceeds from issuance of common stock		—		—		—		300		(300	)		—
Net increase in short-term borrowings from affiliate with original maturities of three months or less		48,472		17,200		—		—		(15,700	)		49,972
Other		1,573		(1,280	)	8		—		—			301
Net cash provided by (used in) financing activities		7,055		4,450		(14,492	)	300		(10,030	)		(12,717	)
Net increase (decrease) in cash and equivalents		(1	)	2,036		4,276		261		—			6,572
Cash and equivalents, beginning of period		9		4		87		58		—			158
Cash and equivalents, end of period	$	8		2,040		4,363		319		—		$	6,730

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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		Reclassifi- cations and eliminations		HECO consoli- dated
Cash flows from operating activities
Income (loss) 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 (loss) 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	)
Contributions 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

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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

	Three months ended September 30,				% change		Primary reason(s) for significant change*
(in thousands, except per share amounts)	2004		2003
Revenues	$	506,759	$	453,703	12	%	Increases for the electric utility and “other” segments, partly offset by a decrease for the bank segment
Operating income		81,686		68,235	20		Improvement for all segments
Income from:
Continuing operations	$	40,759	$	30,522	34		Higher operating income and AFUDC and lower fixed charges, partly offset by higher income taxes (primarily due to an adverse bank franchise tax ruling as discussed in note 4 to HEI’s “Notes to Consolidated Financial Statements” under “ASB Realty Corporation”)
Discontinued operations		1,913		—	NM		HEIPC: gain on transfer of China joint venture interest
Net income	$	42,672	$	30,522	40
Basic earnings per common share—
Continuing operations	$	0.51	$	0.41	24
Discontinued operations		0.02		—	NM
	$	0.53	$	0.41	29		See explanation for income above and weighted-average number of common shares outstanding below
Weighted-average number of common shares outstanding		80,509		75,032	7		Issuances of shares under a common stock offering in March 2004 (4 million shares, split-adjusted) and Company plans

41

	Nine months ended September 30,					% change		Primary reason(s) for significant change*
(in thousands, except per share amounts)	2004		2003
Revenues	$	1,405,667	$	1,327,095		6	%	Increases for the electric utility and “other” segments, slightly offset by a decrease for the bank segment
Operating income		216,469		188,776		15		Improvement for all segments
Income (loss) from:
Continuing operations	$	82,929	$	80,609		3		Higher operating income and AFUDC and lower fixed charges, partly offset by higher income taxes (including a $21 million net charge for cumulative bank franchise taxes through March 31, 2004 due to an adverse tax ruling as discussed in note 4 to HEI’s “Notes to Consolidated Financial Statements” under “ASB Realty Corporation”)
Discontinued operations		1,913		(3,870	)	NM		HEIPC: gain on transfer of China joint venture interest in third quarter of 2004; writedown of investment in CEPALCO by $5 million and increase in reserve for future expenses of $1 million (primarily for legal fees during the longer than expected disposal period) in the second quarter of 2003
Net income	$	84,842	$	76,739		11
Basic earnings (loss) per common share—
Continuing operations	$	1.05	$	1.08		(3	)
Discontinued operations		0.02		(0.05	)	NM
	$	1.07	$	1.03		4		See explanation for income (loss) above and weighted-average number of common shares outstanding below
Weighted-average number of common shares outstanding		79,204		74,410		6		Issuances of shares under a common stock offering in March 2004 (4 million shares, split-adjusted) and Company plans

NM Not meaningful.

* Also see segment discussions which follow.

Stock split

On April 20, 2004, HEI announced a 2-for-1 stock split in the form of a 100% stock dividend with a record date of May 10, 2004 and a distribution date of June 10, 2004. All share and per share information above, in the

42

accompanying financial statements and notes and elsewhere in the Form 10-Q have been adjusted to reflect the stock split (unless otherwise noted). See notes 1 and 9 to HEI’s “Notes to Consolidated Financial Statements.”

Bank franchise taxes

The results of operations for the first nine months of 2004 include a net charge of $24 million, or $0.30 per share, due to an adverse tax ruling as discussed in note 4 to HEI’s “Notes to Consolidated Financial Statements” under “ASB Realty Corporation.” The $24 million net charge includes a net $21 million of cumulative bank franchise taxes through March 31, 2004, plus a net $3 million of interest (which gross interest of $5 million is included in general and administrative expenses of ASB). In addition, ASB accrued $0.4 million of interest, net of taxes, and state bank franchise tax of $1.2 million, net of taxes, related to this tax issue for the period from April 1 to September 30, 2004. The following table presents a reconciliation of HEI’s consolidated net income to net income excluding this $24 million charge and including additional bank franchise taxes in prior periods as if the Company had not taken a dividends received deduction on income from its REIT subsidiary. The Company believes the adjusted information below presents results from continuing operations on a more comparable basis for the periods shown. However, net income, or earnings per share, including these adjustments is not a presentation in accordance with GAAP and may not be comparable to other companies or more useful than the GAAP presentation included in HEI’s consolidated financial statements.

	Three months ended September 30,					Nine months ended September 30,
(in thousands, except per share amounts)	2004		2003			2004			2003
Income from continuing operations	$	40,759	$	30,522		$	82,929		$	80,609
Basic earnings per share—continuing operations	$	0.51	$	0.41		$	1.05		$	1.08
Cumulative bank franchise taxes and interest, net, through March 31, 2004	$	—	$	—		$	23,955		$	—
Additional bank franchise taxes, net (if recorded in prior periods)		—		(1,150	)		(634	)		(3,167	)
Total adjustments	$	—	$	(1,150	)	$	23,321		$	(3,167	)
As adjusted
Income from continuing operations	$	40,759	$	29,372		$	106,250		$	77,442
Basic earnings per share—continuing operations	$	0.51	$	0.39		$	1.34		$	1.04

Taking into account the adjustments in the table above, HEI’s consolidated income from continuing operations would have increased 39% and 37% for the three months and nine months ended September 30, 2004, respectively, compared to the same periods last year as ASB would have had significantly improved operating results, as did the other segments.

Based on reported net income for prior periods, Hawaii bank franchise taxes related to the dividends received deduction, net of federal income tax benefits, would have been as follows for the periods indicated:

	2003				2004
(in thousands)	Quarter		Year-to-date		Quarter
First quarter	$	998	$	998	$	634
Second quarter		1,019		2,017
Third quarter		1,150		3,167
Fourth quarter		626		3,793

43

Pension and other postretirement benefits

For the first nine months of 2004, the retirement benefit plan assets generated a total return of 1.7%, compared to a 9% annual expected return on plan assets assumption and a total return of nearly 25% for 2003, resulting in realized and unrealized net gains of approximately $13 million. The market value of the retirement benefit plans’ assets as of September 30, 2004 was $824 million. Although not required, the Company increased its estimated contributions to the retirement benefit plans due to the lower than expected return on plan assets. The Company made cash contributions to the retirement benefit (i.e., pension and other postretirement benefit) plans totaling $25 million for the first nine months of 2004 and intends to make additional cash contributions of $2 million by December 31, 2004.

Depending on the 2004 investment experience and interest rates at year-end (measurement date), the Company could be required to recognize an additional minimum liability at December 31, 2004 as prescribed by SFAS No. 87, “Employers’ Accounting for Pensions.” The recognition of an additional minimum liability is required if the accumulated benefit obligation exceeds the fair value of plan assets at measurement date. The recognition of an additional minimum liability would also result in the removal of the prepaid pension asset ($95 million at December 31, 2003) from the Company’s balance sheet. The liability would largely be recorded as a reduction to stockholders’ equity through a noncash charge to accumulated other comprehensive income (AOCI), and would not affect net income for 2004. The additional minimum liability does not apply to other postretirement benefits.

The amount of additional minimum liability and charge to AOCI, if any, to be recorded at December 31, 2004, could be material and will depend upon a number of factors, including the year-end discount rate assumption, asset returns experienced in 2004, any changes to actuarial assumptions or plan provisions, and contributions made by the Company to the plans during 2004. In addition, retirement benefits expense and cash funding requirements could increase in future years depending on the performance of the equity markets and changes in interest rates.

In part, the Company benchmarks its discount rate assumption to the Moody’s 20-year AA Corporate Bond Composite Index, which was 5.73% at September 30, 2004 compared to 6.02% at December 31, 2003. The discount rate used at December 31, 2003 was 6.25%. The Company anticipates the discount rate at December 31, 2004 will be between 5.75% and 6.25%.

Based on the market value of the pension plans’ assets as of December 31, 2003 and assuming a range of returns on plan assets of 0% to 9% for 2004, cash contributions of $18 million in 2004, a range of 5.75% to 6.25% for the discount rate at December 31, 2004, and no further changes in assumptions or pension plan provisions, consolidated HEI’s, consolidated HECO’s and ASB’s AOCI balance, net of tax benefits, related to the minimum pension liability at December 31, 2004 is estimated to be as follows:

AOCI balance, net of tax benefits

	Discount rate
($ in millions)	5.75%		6.25%
Consolidated HEI
0% return on plan asset assumption	$	98	$	73
9% return on plan asset assumption		62		1
Consolidated HECO
0% return on plan asset assumption	$	96	$	72
9% return on plan asset assumption		61		—
ASB
0% return on plan asset assumption	$	—	$	—
9% return on plan asset assumption		—		—

If the Company and consolidated HECO are required to record substantially greater charges to AOCI in the future, 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. There also may be possible

44

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 equity to consolidated capitalization of 35% (actual ratio of 54% as of September 30, 2004); the Company maintain a consolidated net worth, exclusive of intangible assets, of at least $900 million (actual net worth, exclusive of intangible assets, of $1.1 billion as of September 30, 2004); and HEI, on a non-consolidated basis, maintain a ratio of indebtedness to capitalization of not more than 50% (actual ratio of 27% as of September 30, 2004). Further, if required to record significant charges to AOCI, the electric utilities’ returns on average rate base (RORs) could increase and exceed the PUC authorized RORs, which may ultimately result in reduced revenues and lower earnings.

Consolidated HEI’s, consolidated HECO’s and ASB’s net periodic pension and other postretirement benefits costs (net of tax benefits) are estimated to be $7 million, $4 million and $2 million, respectively, for 2004 compared to $12 million, $8 million and $3 million, respectively for 2003.

Based on the market value of the retirement benefit plans’ assets as of December 31, 2003 and using the same assumptions used in the estimation of a potential year-end AOCI charge above, 2005 retirement benefit expense, net of amounts capitalized and tax benefits, is expected to be:

Retirement benefit expense, net of amounts capitalized and tax benefits

	Discount rate
($ in millions)	5.75%		6.25%
Consolidated HEI
0% return on plan asset assumption	$	15	$	12
9% return on plan asset assumption		13		10
Consolidated HECO
0% return on plan asset assumption	$	11	$	8
9% return on plan asset assumption		9		6
ASB
0% return on plan asset assumption	$	3	$	3
9% return on plan asset assumption		3		3

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 benefit expenses, along with other factors, may affect the timing and amount of future electric rate increase requests.

Certain expenses

For consolidated HEI, directors and officers insurance premiums for policy year 2004 (from February 1, 2004 through January 31, 2005) will be approximately $1.5 million higher ($0.8 million for HEI corporate, $0.2 million for consolidated HECO and $0.5 million for consolidated ASB) than policy year 2003 for the same level of coverage. Premium increases in 2004 for other lines of insurance coverage were not as substantial.

While not substantial for the first nine months of 2004, 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 systems are on-going, but are not currently expected to result in significantly increased costs for 2004.

Dividends

HEI and its predecessor company, HECO, have paid dividends continuously since 1901. On October 26, 2004, HEI’s Board maintained the quarterly dividend of $0.31 per common share (split-adjusted). The payout ratio for 2003 and the first nine months of 2004 was 81% and 87% (payout ratio of 78% and 89% based on income from continuing operations), respectively. The high payout ratio for the first nine months of 2004 was primarily due to the charge to net income in the second quarter of 2004 of $24 million for cumulative bank franchise taxes and interest through March 31, 2004 due to an adverse tax ruling and an increased number of shares outstanding from the sale of 2 million shares (pre-split) of common stock in March 2004 and the issuance of new common shares to satisfy the requirements of the DRIP and other plans. Adjusting net income for bank franchise taxes, the payout ratio for the nine

45

months ended September 30, 2004 would have been 68% (69% based on income from continuing operations adjusted for bank franchise taxes). In March 2004, the Company began purchasing common shares on the open market to satisfy the requirements of its DRIP and HEIRSP. HEI’s Board and management believe HEI should achieve a 65% payout ratio on a sustainable basis before it considers increasing the common stock dividend above its current level.

Economic conditions

Because its core businesses provide local electric utility and banking services, HEI’s operating results are significantly influenced by the strength of Hawaii’s economy, which has been growing modestly.

Tourism is widely acknowledged as the largest component of the Hawaii economy. Total visitor arrivals were up 8.6% through August 2004, compared to the same period in 2003. Since 9/11, domestic arrivals have been growing and keeping tourism relatively stable. However, key to tourism growth is the return of Japanese tourists to pre-9/11 levels. In 2003, Japan’s economy showed growth for the first time since 2000 and the outlook is for continued growth in 2004 and 2005. Japanese visitor arrivals increased by 17.2% through August 2004 compared with the same period last year, with arrivals in August 2004 up 6.6%.

Key non-tourism sectors in Hawaii, particularly the military and residential real estate, are fueling economic growth. After remaining relatively stable over the last five years, the military is growing its presence in Hawaii. A $1.5 billion brigade of 291 Stryker vehicles was approved for Hawaii, resulting in a projected $693 million in construction projects, the planned acquisition of 1,400 acres on the island of Oahu and 23,000 acres on the island of Hawaii, and the addition of approximately 480 soldiers.

September’s median home prices on Oahu were $475,000 for single-family homes and $219,000 for condominiums, the latter setting a new record high. This represents a 20.3% and 21.7% increase over the same time last year for the prices of single-family homes and condominiums, respectively. The number of resales through September increased by 11.5% as compared to the same period last year contributing to over $3.4 billion in sales volume, a 31% increase over the $2.6 billion produced during the same period of 2003.

Construction activity in Hawaii continues to be strong, with private building permits on Oahu up 14% for the first eight months of 2004 compared with the same period of 2003.

Strength in Hawaii’s economy is also reflected in other general economic statistics. Total salary and wage jobs increased by 2.2% through August 2004 compared with the same period in 2003. Hawaii’s unemployment rate of 2.9% is the lowest in nearly 13 years and well below the national average of 5.4% at the end of August 2004.

Given these positive trends in tourism, key non-tourism sectors and overall economic indicators, the State of Hawaii Department of Business, Economic Development and Tourism (DBEDT) expects Hawaii’s economy to grow moderately by 2.6% in 2004 excluding inflation (compared to 3.2% and 2.6% growth in 2002 and 2003, respectively). Future growth in Hawaii’s economy is expected to be related primarily to the rates of expansion in the mainland U.S. and Japan economies and their effects on tourism, continued strength in real estate and construction activity and increased military spending, and remains vulnerable to uncertainties in the world’s geopolitical environment.

ASB’s operating results are largely impacted by the existing interest rate environment. See “Quantitative and qualitative disclosures about market risk.”

American Jobs Creation Act of 2004

On Friday, October 22, 2004, President Bush signed into law the American Jobs Creation Act of 2004 (the Act), which is expected to have tax implications for the Company. Management is currently reviewing various aspects of the Act. Two notable provisions of the Act, with potential implications for the Company, include:

1. Manufacturing tax incentives for the production of electricity beginning in 2005. Taxpayers will be able to deduct a percentage (3% in 2005 and 2006, 6% in 2007 through 2009, and 9% in 2010 and thereafter) of the lesser of their qualified production activities income or their taxable income.

2. Generally for electricity sold and produced after October 22, 2004, the Act expands the income tax credit for electricity produced from certain sources to include open-loop biomass, geothermal and solar energy, small irrigation power, landfill gas, trash combustion and qualifying refined coal production facilities.

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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
	2004		2003
Revenues	$	410,077	$	359,250	14	%	3.6% higher KWH sales ($12 million) and higher fuel oil and purchased energy fuel costs, the effects of which are generally passed on to customers ($38 million)
Expenses
Fuel oil		128,584		101,296	27		Higher fuel oil costs and more KWHs generated
Purchased power		105,985		92,543	15		Higher fuel costs, higher capacity charges and more KWHs purchased
Other		122,795		118,775	3		Higher other operation expense, depreciation and taxes, other than income taxes, partly offset by lower maintenance expense and a prior year accrual for a potential environmental liability
Operating income		52,713		46,636	13		Higher KWH sales and lower maintenance expense, partly offset by higher capacity charges, other operation expense, depreciation and taxes, other than income taxes
Net income		26,175		20,360	29		Higher operating income and AFUDC and lower interest and other charges, partly offset by higher income taxes
Kilowatthour sales (millions)		2,675		2,583	4
Cooling degree days (Oahu)		1,651		1,639	1
Fuel oil cost per barrel	$	42.72	$	35.62	20

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(dollars in thousands, except per barrel amounts)	Nine months ended September 30,				% change		Primary reason(s) for significant change
	2004		2003
Revenues	$	1,127,295	$	1,042,691	8	%	3.4% higher KWH sales ($35 million) and higher fuel oil and purchased energy fuel costs, the effects of which are generally passed on to customers ($52 million)
Expenses
Fuel oil		340,166		294,303	16		Higher fuel oil costs and more KWHs generated
Purchased power		292,491		273,161	7		Higher fuel costs and more KWHs purchased
Other		351,871		345,031	2		Higher maintenance expense, depreciation and taxes, other than income taxes, partly offset by lower other operation expense (including lower retirement benefit expenses)
Operating income		142,767		130,196	10		Higher KWH sales and lower other operation expense, partly offset by higher maintenance expense, depreciation and taxes, other than income taxes
Net income		67,933		56,572	20		Higher operating income and AFUDC and lower interest and other charges, partly offset by higher income taxes
Kilowatthour sales (millions)		7,516		7,269	3
Cooling degree days (Oahu)		3,883		3,750	4
Fuel oil cost per barrel	$	40.38	$	36.75	10

Kilowatthour (KWH) sales in the third quarter of 2004 increased 3.6% from the same quarter in 2003, primarily due to higher customer usage due in part to the strength in Hawaii’s economy (higher visitor arrivals, increased military activity and strong real estate market) and weather (increased humidity resulting in more air conditioning usage). Electric utility operating income increased 13% from the third quarter 2003, primarily due to higher KWH sales and lower maintenance expense, partly offset by higher other operation and depreciation expenses and taxes, other than income taxes. Other operation expense increased 4% primarily due to higher production operations expense, higher demand side management expense and an increase in general liability reserves, partly offset by lower pension and other postretirement benefit expenses. Pension and other postretirement benefit expenses for the electric utilities decreased $1.9 million from the same period in 2003 ($1.5 million expense in the third quarter of 2004 versus $3.4 million in the third quarter of 2003) due primarily to an increase in the value of plan assets in 2003. Maintenance expense decreased by 4% due to lower generating unit overhauls expense. Higher depreciation expense was attributable to additions to plant in service in 2003.

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KWH sales in the first nine months of 2004 increased 3.4% over the first nine months of 2003, primarily due to higher residential and commercial customer usage due in part to the strength in Hawaii’s economy (higher visitor arrivals, increased military activity and strong real estate market) and weather (increased humidity and cooling degree days resulting in more air conditioning usage). Electric utility operating income increased 10% from the first nine months of 2003, primarily due to higher KWH sales and lower other operation expense, partly offset by higher maintenance and depreciation expenses and taxes, other than income taxes. Other operation expense decreased 4% primarily due to lower pension and other postretirement benefit expenses, and lower emissions fees, partly offset by higher workers compensation claims and an increase in general liability reserves. Pension and other postretirement benefit expenses for the electric utilities decreased $5.9 million over the same period in 2003 ($4.6 million expense in the first nine months of 2004 versus $10.4 million in the first nine months of 2003) due primarily to an increase in the value of plan assets at December 31, 2003 as compared to the value of plan assets at December 31, 2002. Maintenance expense increased by 5% due to increased generating unit overhauls and storm-related expenses in the first quarter of 2004 and lower insurance reimbursements. Higher depreciation expense was attributable to additions to plant in service in 2003.

Competition

The electric utility industry in Hawaii is 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.

Competitive bidding proceeding. In October 2003, the PUC opened investigative dockets on competitive bidding and distributed generation (DG) to move toward a more competitive electric industry environment under cost-based regulation. The stated purpose of the competitive bidding investigation is to evaluate competitive bidding as a mechanism for acquiring or building new generating capacity in Hawaii. The PUC stated it would consider related filings on a case-by-case basis pending completion of these dockets.

The current parties/participants in the competitive bidding proceeding include the Consumer Advocate, HECO, HELCO, MECO, Kauai Island Utility Cooperative, the Gas Company, the Counties of Maui and Kauai, a renewable energy organization and vendors of DG equipment and services. In April 2004, the parties and participants entered into and filed a proposed stipulated prehearing order, and the PUC adopted the issues and procedures proposed for consideration in the stipulated order and the proposed schedule with modifications. The issues to be addressed in the proceeding include the benefits and impacts of competitive bidding, whether a competitive bidding system should be developed for acquiring or building new generation, and revisions that should be made to integrated resource planning. If competitive bidding is adopted, the proceeding will address specific bidding guidelines and requirements that encourage broad participation but do not place ratepayers at undue risk. The procedural schedule includes testimonies by all parties in January 2005, and evidentiary hearings in July 2005. Management cannot predict the ultimate outcome of this proceeding.

Distributed generation proceeding. 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 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 initiated a small CHP demonstration project on Maui in 2002 as part of an on-going evaluation of DG. The electric utilities also have made proposals to customers, subject to PUC review and approval, to install and operate utility-owned CHP systems at the customers’ sites. The electric utilities have executed a number of letters of intent and one memorandum of understanding to conduct preliminary engineering for potential

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CHP projects. The electric utilities have signed agreements with two customers to install, operate and maintain utility-owned CHP systems, subject to PUC review and approval. 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.

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. In August 2003, the electric utilities responded to the informal complaint, and to information requests from the PUC on the CHP demonstration project and a teaming agreement.

In October 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 policies and a framework for DG projects deployed in Hawaii. The parties and participants to the proceeding include the Consumer Advocate, HECO, HELCO, MECO, Kauai Island Utility Cooperative, the Counties of Maui and Kauai, a renewable energy organization, a vendor of DG equipment and services and an environmental organization. In April 2004, the PUC issued an order in the proceeding, based in large part on a stipulated order proposed by the parties and participants that includes 13 planning, impact and implementation issues. The planning issues address (1) forms of DG (e.g., renewable energy facilities, hybrid renewable energy systems, generation, cogeneration) that may be feasible and viable for Hawaii, (2) who should own and operate DG projects, and (3) the role of regulated electric utility companies and the PUC in the deployment of DG in Hawaii. The impact issues address (1) the impacts, if any, DG will have on Hawaii’s electric transmission and distribution systems and market, (2) the impacts of DG on power quality and reliability, (3) utility costs that can be avoided by DG, (4) externalities costs and benefits of DG, and (5) the potential for DG to reduce the use of fossil fuels. Implementation issues include (1) matters to be considered to allow a DG facility to interconnect with the electric utility’s grid, (2) appropriate rate design and cost allocation issues that must be considered with the deployment of DG facilities, (3) revisions that should be made to the integrated resource planning process, and (4) revisions that should be made to PUC rules and utility rules and practices to facilitate the successful deployment of DG. The parties and participants can also address issues raised in the informal complaint, but not specific claims made against any of the parties named in the complaint. The parties and participants filed direct testimonies in July 2004 and rebuttal testimonies in October 2004. The procedural schedule for the proceeding includes evidentiary hearings in December 2004. As a result of the docket on DG, the electric utilities cancelled a teaming agreement for CHP systems with ratings up to 1 MW, entered into in early 2003 with a manufacturer of packaged CHP systems, and issued a request for qualifications as part of a new equipment procurement process for all CHP systems. Management cannot predict the ultimate outcome of this proceeding.

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) pursuant to a standard form of contract with the customer. In March 2004, the PUC issued an order in which it suspended the CHP tariff application until, at a minimum, the matters in the investigative docket on DG have been addressed. Pending approval of a CHP tariff, the electric utilities have requested approval for a CHP project and plan to request approval for additional individual CHP projects as they are developed.

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 decision and order (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. Through September 30, 2004, HECO and its subsidiaries had recognized $17 million of revenues (including interest and revenue taxes) with respect to interim orders regarding

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certain integrated resource planning costs, which revenues are subject to refund, with interest, to the extent they exceed the amounts allowed in final orders. The Consumer Advocate has objected to the recovery of $2.5 million (before interest) of the $10.3 million of incremental integrated resource planning costs incurred during the 1995-2002 period, and the PUC’s decision is pending on this matter. In addition, HECO and MECO incurred approximately $0.6 million of incremental integrated resource planning costs for 2003 and $0.6 million of such costs for the first nine months of 2004. The Consumer Advocate has not yet stated its position on these costs incurred.

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 submitted its notice of intent to file a rate increase application in the second half of 2004, using a 2005 test year, and expects to file in November 2004.

The rate schedules of the electric utility subsidiaries include energy cost adjustment clauses under which electric rates charged to customers are automatically adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power. 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).

The utilities have reached agreement with their suppliers on amendments to their existing fuel supply contracts that will extend the contracts through December 2014 on substantially the same terms and conditions, including market-related pricing, subject to PUC approval. In May 2004, the utilities filed the amendments to the fuel supply contracts with the PUC and are awaiting approval.

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. See the discussion below under “Most recent rate requests” for the disposition of this application.

In May 2004, the PUC issued a D&O authorizing an increase from $0.5 million to $2.5 million, effective July 1, 2004, in the threshold for capital improvement projects requiring advance PUC review. This increase generally reflects the cumulative effects of inflation on the value of the dollar since the review requirement was originally established in 1965.

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., higher purchased power capacity charges) and the cost of plant and equipment, including the cost of new capital projects to maintain and improve service reliability. 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 2003, the actual simple average ROACEs (semiannually calculated under the rate-making method and reported to the PUC) for HECO, HELCO and MECO were 9.20%, 6.61% and 10.08%, respectively. HELCO’s actual 6.61% ROACE for 2003, which is substantially less than its allowed ROACE of 11.50%, reflects in part HELCO’s decision to discontinue accruing AFUDC, effective December 1, 1998, on its CT-4 and CT-5 generating units that are being installed at the Keahole power plant. The non-accrual of AFUDC continued to have a negative impact on HELCO’s ROACE for the first half of 2004. As a significant portion of the costs for CT-4 and CT-5 has been transferred from construction in progress to plant in service in 2004, however, the non-accrual of AFUDC on the remaining CT-4 and CT-5 costs in construction in progress is expected to have a smaller negative impact on HELCO’s ROACE for 2004. Nevertheless, HELCO’s ROACE will continue to be negatively impacted as electric rates

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will not change for the additions of CT-4 and CT-5 until HELCO files a rate increase application and the PUC grants HELCO rate relief. For the twelve months ended June 30, 2004, the weighted average ROACEs (rate-making method) for HECO, HELCO and MECO were 9.94%, 6.13% and 10.34%, respectively.

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 2003, the actual RORs (semiannually calculated under the rate-making method and reported to the PUC) for HECO, HELCO and MECO were 7.95%, 8.65% and 8.79%, respectively. For the twelve months ended June 30, 2004, the weighted average RORs (rate-making method) for HECO, HELCO and MECO were 8.35%, 8.03% and 9.18%, respectively.

If required to record significant charges to AOCI, as described previously under “Pension and other postretirement benefits,” the electric utilities’ RORs could increase and exceed the PUC authorized RORs, which may ultimately result in reduced revenues and lower earnings.

Hawaiian Electric Company, Inc. HECO has not initiated a rate case since 1993, but in 2001 it committed to initiate a rate case within three years, using a 2003 or 2004 test year. The PUC later approved HECO’s request that the time for initiating the rate case be extended by 12 months, with the result that the rate case is to be initiated in the second half of 2004, using a 2005 test year. See the discussion below under “Other regulatory matters, Demand-side management programs – agreements with the Consumer Advocate.” In May 2004, HECO filed with the PUC a Notice of Intent to file a general rate increase application. HECO expects to file its rate case in November 2004.

In October 2002, HECO filed an application with the PUC for approval to change its depreciation rates based on a study of depreciation expense for 2000 and to change to vintage amortization accounting for selected plant accounts. 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 2000 depreciation expense. In March 2004, HECO and the Consumer Advocate reached an agreement, subject to PUC approval, under which HECO would make the changes effective with the PUC’s final D&O on HECO’s application. In September 2004, the PUC approved the agreement, and HECO changed its depreciation rates and changed to vintage amortization accounting for selected plant accounts. If the new rates and accounting had been in effect from the beginning of 2004, depreciation expense for the first eight months of 2004 would have been an estimated $1.3 million lower.

Hawaii Electric Light Company, Inc. The timing of a future HELCO rate increase request to recover costs relating to the delayed installation of two combustion turbines (CT-4 and CT-5) at Keahole will depend on future circumstances. See “HELCO power situation” in note 5 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 are 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, for the continuation of HECO’s three commercial and industrial DSM programs and two residential DSM programs until HECO’s next rate case, which HECO committed to file using a 2003 or 2004 test year. These agreements were in lieu of HECO continuing to seek

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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 on rate base 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. In October 2001, HELCO and MECO reached similar 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.

One of the conditions to the temporary continuation of the DSM programs requires the utilities and the Consumer Advocate to review, every six months, the economic and rate impacts resulting from implementing the agreement. In reviewing HELCO’s ROR for 2003, the Consumer Advocate raised an issue as to whether the Keahole settlement expenses accrued in November 2003 should be included in the rate-making calculation for HELCO’s ROR for the purpose of determining whether HELCO’s ROR exceeded its current “authorized” ROR due to its recovery of lost margins and shareholder incentives. Excluding the $3.1 million amount accrued in November 2003, HELCO’s ROR for 2003 would have exceeded HELCO’s current authorized ROR by an amount greater than HELCO’s lost margins and shareholder incentives for the year. In order to resolve any issue of whether HELCO’s recovery of lost margins and shareholder incentives allowed HELCO to exceed its current authorized ROR, HELCO agreed to refund, with interest, all of the lost margins and shareholder incentives earned in 2003. In June 2004, HELCO recorded reduced revenues of $1.1 million to reflect the lost margins and shareholder incentives for 2003 that were refunded to customers in August 2004. No issues have been raised regarding the lost margins and shareholder incentives earned by HECO or MECO in 2003.

As part of HECO’s agreement with the Consumer Advocate regarding HECO’s commercial, industrial and residential DSM programs, the parties agreed in August 2003, and the PUC approved, that HECO could delay the filing of its next rate case by approximately 12 months, with the result that the rate case is currently expected to be filed in November 2004 using a 2005 test year. The other components of the existing agreements, as approved by the PUC, would be continued under the new agreements.

In mid-2004, HECO and the Consumer Advocate reached agreement on a residential load management program and a commercial and industrial load management program and filed the agreements with the PUC requesting expedited approval. In October 2004, the PUC approved HECO’s residential and commercial and industrial load management programs, and the implementation of these programs is expected to begin in early 2005. The residential load management program includes a monthly electric bill credit for eligible customers who participate in the program, which allows HECO to disconnect the customer’s residential electric water heaters from HECO’s system to reduce system load when deemed necessary by HECO. The commercial and industrial load management program provides an incentive on the portion of the demand load that eligible customers allow to be controlled or interrupted by HECO. In addition, if HECO interrupts the load, an incentive is paid on the kilowatthours interrupted.

Avoided cost generic docket. In May 1992, the PUC instituted a generic investigation including all of Hawaii’s electric utilities to examine the proxy method and the proxy method formula used by the electric utilities to calculate their avoided energy costs and Schedule Q rates. In addition to the electric utilities, the parties to the 1992 docket include the Consumer Advocate, the Department of Defense, and representatives of existing or potential independent power producers. In March 1994, the parties entered into and filed a Stipulation to Resolve Proceedings, which is subject to PUC approval. The parties could not reach agreement with respect to certain of the issues, which are addressed in Statements of Position filed in March 1994. No further action was taken in the docket until July 2004, at which time the PUC ordered the parties to review and update, if necessary, the agreements, information and data contained in

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the stipulation and file such information within 60 days of the date of the order, and stated that further action will follow. In September 2004, the PUC approved a request for an extension of time until the end of March 2005 for all parties to submit the requested information.

Collective bargaining agreements

See “Collective bargaining agreements” in note 5 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 2001 Hawaii Legislature adopted a law which required the utilities to meet a renewable portfolio standard of 7% by December 31, 2003. The Company met this standard because over 8% of the utilities’ consolidated electricity sales for 2003 were from renewable resources (as defined under the renewable portfolio standards law). However, the 2004 Hawaii Legislature amended the renewable portfolio standards law to require electric utilities to meet a renewable portfolio standard of 8% by December 31, 2005, 10% by December 31, 2010, 15% by December 31, 2015 and 20% by December 31, 2020, but the amended law contains no penalties if the standards are not met. HECO, HELCO and MECO are permitted to aggregate their renewable portfolios in order to achieve these standards. The PUC has to determine if an electric utility is not able to meet the standard in a cost-effective manner or due to circumstances beyond its control. If such a determination is made, the utility is relieved of its responsibility to achieve the standard for that period of time. The law also requires participation by the State to support and facilitate achievement of the renewable portfolio standards and directs the PUC to develop and implement a rate structure to encourage the use of renewable energy. An independent, peer-reviewed study will be conducted by the Hawaii Natural Energy Institute. The study will look at the electric utilities’ capability of achieving the standards based on a number of factors including impact on consumer rates, utility system reliability and stability, costs and availability of appropriate renewable energy resources and technologies, permitting approvals, and impacts on the economy, culture, community and environment. While the Company met the 7% target for 2003, it believes it may be difficult to meet the standard in future years, particularly if sales of electricity increase as projected. Thus, at this time, management cannot predict the impact of this law or of other proposed congressional and Hawaii legislation on the Company or its customers.

The Company currently supports 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). On December 30, 2003, HELCO signed an approximately 10 MW as-available wind power contract with Hawi Renewable Development, and the contract was approved by the PUC on May 14, 2004. Further, a contract with Apollo Energy Corporation to repower an existing 7 MW windfarm to 20 MW was signed on October 13, 2004, and an application for PUC approval will be submitted soon.

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 an unregulated subsidiary, Renewable Hawaii, Inc. (RHI), with initial approval to invest up to $10 million in renewable energy projects. Beginning in 2003, RHI solicited competitive proposals for investment opportunities in projects (1 MW or larger) to supply renewable energy on the islands of Oahu, Maui, Molokai, Lanai and Hawaii. 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. RHI has signed a memorandum of understanding (MOU) and project agreement for a small-scale municipal solid waste project and a MOU for a small-scale landfill gas project. Investments by RHI will be made only after the developers secure the necessary approvals and permits and an approved PPA with HECO, HELCO or MECO.

Hawaii has a net energy metering law, which requires that electric utilities offer net energy metering to eligible customer generators (i.e. a customer generator may be a net user or supplier of energy and will make payment to or

54

receive credit from the electric utility accordingly). The 2004 Legislature amended the net energy metering law by expanding the definition of “eligible customer generator” to include government entities, increasing the size of eligible net metered systems from 10 kilowatts (kw) to 50 kw, and limiting exemptions from additional requirements for systems meeting safety and performance standards to systems of 10 kw or less. These amendments could have a negative effect on electric utility sales. However, based on experience under the 10 kw limit and assessment of market opportunity for 50 kw applications, management does not expect any such effect to be material.

The 2004 legislature also passed legislation that clarifies that the accepting agency or authority for an EIS is not required to be the approving agency for the permit or approval and also requires an environmental assessment for proposed waste-to-energy facilities, landfills, oil refineries, power-generating facilities greater than 5 MW and wastewater facilities, except individual wastewater systems. This legislation could result in an increase in project costs.

Other developments

HECO has completed a small-scale technical feasibility trial of the “Broadband over Power Line” (BPL) technology in Honolulu, and is now proceeding with a medium scale pilot in an expanded residential/commercial area in Honolulu. The purpose of this pilot is to continue to evaluate the technical feasibility of the BPL technology and its applications in a variety of configurations and environments. BPL-enabled utility applications to be evaluated include distribution system monitoring and control, advanced remote metering, and direct residential load control. Although its evaluation will be focused primarily on utility applications of BPL, HECO will also be evaluating broadband information services that might potentially be provided by other service providers. The pilot will involve 100 residential subscribers in overhead, underground, and multi-dwelling unit electric distribution environments, as well as 5 units in a hotel. The pilot will commence in 2005 and run for approximately 6 to 12 months.

On October 28, 2004, the Federal Communications Commission (FCC) released a Report and Order In the Matter of Amendment of Part 15 Regarding New Requirements and Measurement Guidelines for Access Broadband Over Power Line Systems and In the Matter of Carrier Current Systems, Including Broadband Over Power Line Systems. The Report and Order amends and adopts new rules for Access Broadband over Power Line systems (Access BPL) and states that the FCC’s goals “in developing the rules for Access BPL . . . are therefore to provide a framework that will both facilitate the rapid introduction and development of BPL systems and protect licensed radio services from harmful interference.”

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Bank

	Three months ended September 30,						% change		Primary reason(s) for significant change
(in thousands)	2004			2003
Revenues	$	90,296		$	93,770		(4	)%	Lower fee income on loans serviced for others due to a $1.9 million mortgage servicing rights valuation allowance reversal in 2003 and lower gain on sale of securities, partly offset by higher interest income (resulting from higher average asset balances, partly offset by lower weighted-average yields on loans and investments)
Operating income		26,531			25,116		6		Higher net interest income and reversal of $3.8 million of provision for loan losses, partly offset by lower other income and higher general and administrative expenses
Net income		15,378			15,275		1		Higher operating income, partly offset by higher income taxes (primarily due to an adverse bank franchise tax ruling)
Interest rate spread		3.09	%		3.01	%	3		16 basis points decrease in the weighted-average rate on interest-bearing liabilities, partly offset by a 8 basis points decrease in the weighted-average yield on interest-earning assets

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	Nine months ended September 30,						% change		Primary reason(s) for significant change
(in thousands)	2004			2003
Revenues	$	269,536		$	281,575		(4	)%	Lower interest income (resulting from lower weighted-average yields on loans and investments, partly offset by the impact of higher average asset balances) and lower gain on sale of securities
Operating income		75,650			69,903		8		Higher net interest income and reversal of $8.4 million of provision for loan losses, partly offset by lower other income and higher general and administrative expenses (including $5.5 million of interest accrued on cumulative bank franchise taxes as a result of an adverse tax ruling)
Net income		24,356			42,277		(42	)	Higher income taxes (including $21 million net charge for cumulative bank franchise taxes through March 31, 2004 plus additional bank franchise taxes for the second and third quarters of 2004 as a result of an adverse tax ruling), partly offset by higher operating income
Interest rate spread		3.07	%		3.06	%	—		32 basis points decrease in the weighted-average rate on interest-bearing liabilities, largely offset by a 31 basis points decrease in the weighted-average yield on interest-earning assets

Bank franchise taxes

The results of operations for the nine months ended September 30, 2004 include a net charge of $24 million due to an adverse tax ruling as discussed in note 4 to HEI’s “Notes to Consolidated Financial Statements” under “ASB Realty Corporation.” The $24 million net charge includes a net $21 million of cumulative bank franchise taxes through March 31, 2004, plus a net $3 million of interest (which gross interest of $5 million is included in general and administrative expenses). Also in the second and third quarter of 2004, ASB accrued $0.4 million of interest, net of taxes, and state bank franchise tax of $1.2 million, net of taxes, related to this tax issue for the period from April 1 to September 30, 2004. The following table presents a reconciliation of ASB’s net income to net income excluding the $24 million charge and including additional bank franchise taxes in prior periods as if ASB had not taken a dividends received deduction on income from its REIT subsidiary. Management believes the adjusted information below presents ASB’s net income on a more comparable basis for the periods shown. However, net income, including these adjustments, is not a presentation in accordance with GAAP and may not be comparable to other companies or more useful than the GAAP presentation included in HEI’s consolidated financial statements.

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	Three months ended September 30,					Nine months ended September 30,
(in thousands)	2004		2003			2004			2003
Net income	$	15,378	$	15,275		$	24,356		$	42,277
Cumulative bank franchise taxes and interest, net, through March 31, 2004	$	—	$	—		$	23,955		$	—
Additional bank franchise taxes, net (if recorded in prior periods)		—		(1,150	)		(634	)		(3,167	)
Total adjustments	$	—	$	(1,150	)	$	23,321		$	(3,167	)
Net income—as adjusted	$	15,378	$	14,125		$	47,677		$	39,110

Taking into account the adjustments in the table above, ASB’s net income would have increased 9% and 22% for the three months and nine months ended September 30, 2004, respectively, compared to the same periods last year.

Based on reported net income for prior periods, Hawaii bank franchise taxes related to the dividends received deduction, net of federal income tax benefits, would have been as follows for the periods indicated:

	2003				2004
(in thousands)	Quarter		Year-to-date		Quarter
First quarter	$	998	$	998	$	634
Second quarter		1,019		2,017
Third quarter		1,150		3,167
Fourth quarter		626		3,793

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, 2004, ASB’s loan portfolio mix consisted of 78% residential loans, 8% business loans, 7% consumer loans and 7% commercial real estate loans. At December 31, 2003, ASB’s loan portfolio mix consisted of 78% residential loans, 9% business loans, 7% 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.

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, 2004, ASB’s costing liabilities consisted of 50% core deposits, 20% term certificates and 30% FHLB advances and other borrowings. At December 31, 2003, ASB’s costing liabilities consisted of 48% core deposits, 20% term certificates and 32% 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 (including interest accrued on the unfunded cumulative bank franchise tax liability).

Low interest rates and high mortgage refinancing volume in 2003 and the first half of 2004 have put pressure on ASB’s interest rate spread as the loan portfolio repriced upon refinancing at lower interest rates, while at the same time deposit rates were already at low levels in 2003. At the end of June 2004, the Federal Reserve Bank began raising short term interest rates, putting upward pressure on ASB’s short-term borrowing rates. 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 the 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 September 30, 2004 and December 31, 2003, the unrealized losses, net of tax benefits, on available-for-sale

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mortgage-related securities (including securities pledged for repurchase agreements) in AOCI was $3 million and $1 million, respectively, reflecting the impact of higher interest rates in 2004. 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)	2004		2003		Change			2004		2003		Change
Loans receivable
Average balances1	$	3,109,629	$	3,127,709	$	(18,080	)	$	3,101,378	$	3,059,889	$	41,489
Interest income2		45,504		49,657		(4,153	)		137,745		150,555		(12,810	)
Weighted-average yield (%)		5.85		6.35		(0.50	)		5.92		6.56		(0.64	)
Mortgage-related securities
Average balances	$	2,834,210	$	2,707,368	$	126,842		$	2,761,433	$	2,712,423	$	49,010
Interest income		29,608		24,876		4,732			84,244		80,176		4,068
Weighted-average yield (%)		4.18		3.68		0.50			4.07		3.94		0.13
Investments3
Average balances	$	226,568	$	182,843	$	43,725		$	248,180	$	195,701	$	52,479
Interest and dividend income		1,619		1,428		191			5,032		4,736		296
Weighted-average yield (%)		2.84		3.09		(0.25	)		2.70		3.23		(0.53	)
Total interest-earning assets
Average balances	$	6,170,407	$	6,017,920	$	152,487		$	6,110,991	$	5,968,013	$	142,978
Interest and dividend income		76,731		75,961		770			227,021		235,467		(8,446	)
Weighted-average yield (%)		4.97		5.05		(0.08	)		4.95		5.26		(0.31	)
Deposit liabilities
Average balances	$	4,136,084	$	3,919,376	$	216,708		$	4,073,840	$	3,855,770	$	218,070
Interest expense		11,660		13,099		(1,439	)		35,334		41,182		(5,848	)
Weighted-average rate (%)		1.12		1.33		(0.21	)		1.16		1.43		(0.27	)
Borrowings
Average balances	$	1,812,664	$	1,885,260	$	(72,596	)	$	1,820,345	$	1,862,144	$	(41,799	)
Interest expense		16,488		16,736		(248	)		47,809		53,126		(5,317	)
Weighted-average rate (%)		3.60		3.51		0.09			3.49		3.80		(0.31	)
Total interest-bearing liabilities
Average balances	$	5,948,748	$	5,804,636	$	144,112		$	5,894,185	$	5,717,914	$	176,271
Interest expense		28,148		29,835		(1,687	)		83,143		94,308		(11,165	)
Weighted-average rate (%)		1.88		2.04		(0.16	)		1.88		2.20		(0.32	)
Net average balance, net interest income and interest rate spread
Net average balance	$	221,659	$	213,284	$	8,375		$	216,806	$	250,099	$	(33,293	)
Net interest income		48,583		46,126		2,457			143,878		141,159		2,719
Interest rate spread (%)		3.09		3.01		0.08			3.07		3.06		0.01

¹ Includes nonaccrual loans.

² Includes interest accrued prior to suspension of interest accrual on nonaccrual loans and loan fees of $1.3 million and $2.3 million for the three months ended September 30, 2004 and 2003, respectively, and $4.6 million and $6.1 million for the nine months ended September 30, 2004 and 2003, respectively.

³ Includes stock in the FHLB of Seattle.

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Three months ended September 30, 2004

Net interest income before provision for losses for the third quarter of 2004 increased by $2.5 million, or 5.3%, from the same period in 2003. Net interest spread increased from 3.01% for the third quarter of 2003 to 3.09% for the third quarter of 2004 as ASB’s yield on interest-earning assets decreased slower than the cost of interest-bearing liabilities. The average loan receivables balance decreased slightly in the third quarter of 2004 compared to the same period in the previous year. The increases in the average investment and mortgage-related securities portfolios in the third quarter of 2004 compared to the third quarter in 2003 were due to the reinvestment of excess liquidity into short-term investments. The increase in average deposit balances in the third quarter of 2004 compared to the third quarter in 2003 was due to an increase of $288 million in average core deposit balances, offset by a decrease of $71 million in average term certificate balances. The higher deposit balances enabled ASB to repay some of its maturing, higher costing FHLB advances and other borrowings.

As of September 30, 2004, delinquent and nonaccrual loans to total loans remain well below historical norms at 0.45%. Considerable strength in residential real estate and business conditions continue to have a positive impact on the credit profile of the loan portfolio as evidenced by continuing low delinquencies and reduced net charge-offs. Delinquencies continued to trend lower and net charge-offs for the third quarter of 2004 were lower than the net charge-offs in the second quarter of 2004. Improving qualitative factors such as continued strength in the local economy, housing price trends and liquidity of businesses have kept delinquencies to low levels and reduced net charge-offs. Accordingly, ASB recognized a $3.8 million reversal of the allowance for loan losses during the third quarter of 2004. This compares with a provision for loan losses of $0.6 million for the same period in the previous year. Variables such as the state of the real estate market in Hawaii and the interest rate environment can impact ASB’s loan loss reserve amounts and management cannot predict whether there will be loan loss reversals or increases in the future.

Other income for the third quarter of 2004 decreased by $4.2 million, or 23.8%, compared to the same period in 2003. For the third quarter of 2004, the bank recorded a $0.3 million writedown of its mortgage servicing rights. For the third quarter of 2003, the bank recorded a $1.9 million reversal of its mortgage servicing rights valuation allowance due to slower forecasted prepayments on its servicing portfolio. Also for the third quarter of 2003, the bank realized gains on sales of mortgage-related securities of $1.7 million as ASB sold securities to manage the prepayment risk in its mortgage-related securities portfolio.

General and administrative expenses for the third quarter of 2004 increased by $1.2 million, or 3.1%, compared to the same period in 2003. Compensation and employee benefits expense was 5.2% lower primarily as a result of lower commissions paid to residential loan officers. In the third quarter of 2004, ASB accrued $0.3 million in interest related to the potential bank franchise taxes. ASB also accrued $0.6 million of additional bank franchise taxes, net of tax benefits, because ASB did not recognize the benefit of the dividends received deduction in the third quarter of 2004. For a discussion of an ongoing dispute with state tax authorities relating to the tax treatment of dividends paid to ASB by ASB Realty Corporation, see “ASB Realty Corporation” in note 4 of HEI’s “Notes to Consolidated Financial Statements.”

Nine months ended September 30, 2004

Net interest income before provision for losses for the first nine months of 2004 increased by $2.7 million, or 1.9%, from the same period in 2003. Net interest spread increased from 3.06% for the first nine months of 2003 to 3.07% for the first nine months of 2004 as ASB’s yield on interest-earning assets decreased slightly slower than the cost of interest-bearing liabilities. The increase in the average loan portfolio balance (primarily an increase in the residential loan portfolio) was due to the strong Hawaii real estate market and low interest rates, which resulted in increased affordability of housing for consumers and higher loan refinancings. The increase in the average investment and mortgage-related securities portfolios were due to the reinvestment into short-term investments of excess liquidity resulting from an inflow of deposits. The increase in average deposit balances was due to an increase of $298 million in average core deposit balances, offset by a decrease of $80 million in average term certificate balances. The higher deposit balances enabled ASB to repay some of its maturing, higher costing FHLB advances.

Due to the considerable strength in residential real estate and business conditions, which has resulted in lower historical loss ratios and lower net charge-offs for ASB, and other factors discussed above, ASB was able to

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recognize an $8.4 million reversal of allowance for loan losses during the first nine months of 2004. This compares with a provision for loan losses of $2.8 million for the same period in the previous year. As of September 30, 2004, ASB’s allowance for loan losses was 1.11% of average loans outstanding, compared to 1.48% at September 30, 2003. The following table presents the changes in the allowance for loan losses for the periods indicated:

Nine months ended September 30	2004			2003
(in thousands)
Allowance for loan losses, January 1	$	44,285		$	45,435
Provision for loan losses		(8,400	)		2,775
Net charge-offs		(1,313	)		(3,005	)
Allowance for loan losses, September 30	$	34,572		$	45,205

Other income for the first nine months of 2004 decreased by $3.6 million, or 7.8%, compared to the same period in 2003. Higher fee income on deposit liabilities in the first nine months of 2004 compared to the same period in 2003 were more than offset by lower gains on sales of mortgage-related securities.

General and administrative expenses for the first nine months of 2004 increased by $4.6 million, or 4.0%, from the same period in 2003, mostly related to the $5.5 million of interest on cumulative bank franchise taxes accrued in the second and third quarters of 2004, partly offset by lower compensation and employee benefits expense of $2.2 million and lower consulting and other services expense of $1.1 million. The decrease in compensation and employee benefits expense was primarily a result of lower commissions paid to residential loan officers. Consulting and other services expense incurred in the transformation of ASB from a traditional retail thrift to a full-service community bank was lower due to the timing of certain transformation activities.

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 the low interest rate environment prevailing at the time, 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.”

Regulation

ASB is subject to extensive regulation, principally by the Office of Thrift Supervision (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.”

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Other

	Three months ended September 30,					% change		Primary reason(s) for significant change
(in thousands)	2004		2003
Revenues	$	6,386	$	683		835	%	Gain on sale of income notes ($6 million) in 2004
Operating income (loss)		2,442		(3,517	)	NM		Higher revenues and lower legal and charitable contribution expenses

	Nine months ended September 30,						% change		Primary reason(s) for significant change
(in thousands)	2004			2003
Revenues	$	8,836		$	2,829		212	%	Gain on sale of and higher income from income notes ($7 million) in 2004
Operating loss		(1,948	)		(11,323	)	NM		Higher revenues and lower legal and charitable contribution expenses

NM Not meaningful.

The “other” business segment includes results of operations of HEI Investments, Inc., a company primarily holding investments in leveraged leases; Pacific Energy Conservation Services, Inc., a contract services company primarily providing windfarm operational and maintenance services to an affiliated electric utility; HEI Properties, Inc. (HEIPI), a company holding passive investments; Hawaiian Electric Industries Capital Trust I and its subsidiary (HEI Preferred Funding, LP), which were deconsolidated on January 1, 2004 and dissolved in April 2004, and Hycap Management, Inc., financing entities formed to effect the issuance of 8.36% Trust Originated Preferred Securities; The Old Oahu Tug Service, Inc. (TOOTS), a maritime freight transportation company that ceased operations in 1999; HEI and HEIDI, holding companies; and eliminations of intercompany transactions. The first seven months of 2003 also includes the results of operations for 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, which was sold for a nominal loss in July 2003; and two other inactive subsidiaries, HEI Leasing, Inc. and HEI District Cooling, Inc., which were dissolved in October 2003. In August 2004, HEI sold its investments in the income notes (CDOs), which it had acquired from ASB in 2001, for a net gain of $5.6 million ($3.6 million after-tax).

Discontinued operations

See note 5 in HEI’s “Notes to Consolidated Financial Statements.”

Contingencies

See note 10 and note 5 in HEI’s and HECO’s respective “Notes to Consolidated Financial Statements.”

Recent accounting pronouncements and interpretations

See note 12 and note 7 in HEI’s and HECO’s respective “Notes to Consolidated Financial Statements.”

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FINANCIAL CONDITION

Liquidity and capital resources

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

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

(in millions)	September 30, 2004				December 31, 2003
Short-term borrowings	$	8	1	%	$	—	—	%
Long-term debt, net		1,167	48			1,065	45
HEI-and HECO-obligated preferred securities of trust subsidiaries		—	—			200	8
Preferred stock of subsidiaries		34	1			34	1
Common stock equity		1,212	50			1,089	46
	$	2,421	100	%	$	2,388	100	%

See notes 7 and 12 of HEI’s “Notes to Consolidated Financial Statements” for an explanation of the deconsolidation of financing entities and refinancing transactions.

As of November 1, 2004, 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	BBB	Baa2
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.

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

On March 16, 2004, HEI completed the sale of 2 million shares (pre-split) of common stock. The shares were issued under an omnibus shelf registration statement registering up to $200 million of debt, equity and/or other securities. The net proceeds from the sale of approximately $99 million were ultimately used, along with other corporate funds, to effect the redemption of $100 million aggregate principal amount of 8.36% Trust Originated Preferred Securities of Hawaiian Electric Industries Capital Trust I on April 16, 2004. At September 30, 2004, an additional $96 million of debt, equity and/or other securities were available for offering by HEI under the omnibus shelf registration.

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On March 17, 2004, HEI completed the sale of $50 million of 4.23% notes, Series D, due March 15, 2011 under its registered medium-term note program. The net proceeds from this sale were ultimately used to make short-term loans to HECO, to assist HECO and HELCO in redeeming the 7.30% Cumulative Quarterly Income Preferred Securities, Series 1998, in April 2004 and for other general corporate purposes. It is anticipated that HECO will repay those short-term loans by the end of 2004 primarily with funds saved from reducing dividends to HEI in 2004. For the first nine months of 2004, HECO’s dividends to HEI were $11.6 million, compared to $42.4 million in the same period in 2003.

On March 7, 2003, HEI sold $50 million of its 4.00% notes, Series D, due March 7, 2008, and $50 million of its 5.25% notes, Series D, due March 7, 2013 under its registered medium-term note program. The net proceeds from the sales, along with other corporate funds, were ultimately used to repay $100 million of notes, Series C, (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, 2004, an additional $150 million principal amount of Series D notes were available for offering by HEI under its registered medium-term note 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 may borrow from or loan to HELCO and MECO short-term. At September 30, 2004, HECO had $48 million and $24 million of short-term borrowings from HEI and MECO, respectively, and HELCO had $28 million of short-term borrowings from HECO. HEI had no commercial paper borrowings during the first nine months of 2004. HECO had an average outstanding balance of commercial paper for the first nine months of 2004 of $9 million and had $8 million of commercial paper outstanding at September 30, 2004.

At September 30, 2004, HEI and HECO maintained bank lines of credit totaling $80 million and $90 million, respectively (all maturing in 2005, except $10 million of HEI’s lines, originally maturing in October 2004, but whose maturity has been extended to October 2005 and whose credit line has been increased to $15 million, and $20 million of HEI’s lines maturing in December 2004). These lines of credit are principally maintained by HEI and HECO to support the issuance of commercial paper, but 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 12.5 to 20 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 or other material adverse events. At September 30, 2004, 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 2004, net cash provided by operating activities of consolidated HEI was $234 million. Net cash used in investing activities was $308 million, due to ASB’s purchase of mortgage-related securities, net of repayments and sales and HECO’s consolidated capital expenditures, partly offset by ASB’s repayments of loans, net of originations and purchases, and distributions from unconsolidated financing entities. Net cash provided by financing activities was $38 million as a result of several factors, including net increases in deposit liabilities, short-term borrowings and advances from the Federal Home Loan Bank and proceeds from the issuance of common stock and medium-term notes, partly offset by net repayments of securities sold under agreements to repurchase, long-term debt (related to trust preferred securities) and nonrecourse debt of leveraged leases and the payment of common dividends.

Forecast HEI consolidated “net cash used in investing activities” (excluding “investing” cash flows from ASB) for 2004 through 2008 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 $208 million will be required during 2004 through 2008 to repay maturing HEI long-term debt, which is expected to be repaid with the

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proceeds from the sale of medium-term notes, common stock or other securities. Additional debt and/or equity financing may be required to fund unanticipated expenditures not included in the 2004 through 2008 forecast, such as increases in the costs of or an acceleration of the construction of capital projects of the electric utilities, unbudgeted acquisitions or investments in new businesses, significant increases in retirement benefit funding requirements that might be required if there were significant declines in the market value of pension plan assets or changes in actuarial assumptions and higher tax payments that would result if tax positions taken by the Company do not prevail. Existing debt may be refinanced (potentially at more favorable rates) with additional debt or equity financing (or both).

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, 2004				December 31, 2003
Short-term borrowings	$	56	3	%	$	6	—	%
Long-term debt, net		752	41			699	39
HECO-obligated preferred securities of trust subsidiaries		—	—			100	6
Preferred stock		34	2			34	2
Common stock equity		1,004	54			945	53
	$	1,846	100	%	$	1,784	100	%

See notes 2 and 7 of HECO’s “Notes to Consolidated Financial Statements” for an explanation of the non-consolidation of trust subsidiary financing entities and refinancing transactions.

Operating activities provided $147 million in net cash during the first nine months of 2004. Investing activities used net cash of $127 million primarily for capital expenditures, net of contributions in aid of construction. Financing activities used net cash of $13 million, primarily due to the net repayment of long-term debt of $51 million and payment of $12 million in common and preferred dividends, partly offset by a $50 million net increase in short term borrowings.

As of September 30, 2004, approximately $13 million of proceeds from the sale by the Department of Budget and Finance of the State of Hawaii of Series 2002A Special Purpose Revenue Bonds (SPRB) issued for the benefit of HECO 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 of the State of Hawaii 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. On June 2, 2003, the proceeds of these Refunding SPRB, together with additional funds provided by HECO and HELCO, were 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).

In October 2004, the electric utilities filed an application with the PUC seeking authority to participate with the Department of Budget and Finance of the State of Hawaii in the issuance of refunding special purpose revenue bonds, with the proceeds of such bonds, if issued, to be used to redeem the 6.6% Series 1995A Special Purpose Revenue Bonds, which are callable on or after January 1, 2005. The decision whether and, if so, when to issue refunding special purpose revenue bonds and/or to call the 6.6% Series 1995A Special Purpose Revenue Bonds will depend on future market conditions and other considerations.

On March 18, 2004, HECO Capital Trust III issued and sold 2 million of its 6.50% Cumulative Quarterly Income Preferred Securities ($50 million aggregate liquidation preference). Also on March 18, 2004, HECO, HELCO and MECO issued 6.50% Junior Subordinated Deferrable Interest Debentures to HECO Capital Trust III in the aggregate principal amount of approximately $51.5 million and directed that the proceeds from the issuance of the debentures

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be deposited with the trustee for HECO Capital Trust I and ultimately be used in April 2004 to redeem its 8.05% Cumulative Quarterly Income Preferred Securities ($50 million aggregate liquidation preference) and its common securities (owned by HECO) of approximately $1.5 million. The financial statements of HECO Capital Trust III are not consolidated in the HECO consolidated financial statements and the Junior Subordinated Deferrable Interest Debentures are included in “Long-term debt, net” in the HECO consolidated financial statements. Also in April 2004, HECO Capital Trust II redeemed $50 million aggregate liquidation preference of its 7.30% Cumulative Quarterly Income Preferred Securities primarily using funds from short-term borrowings from HEI and from the issuance of commercial paper.

The electric utilities’ net capital expenditures for 2004 through 2008 are estimated to total $760 million. 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 to cover the forecast consolidated net capital expenditures, except for a projected slight increase in short-term borrowings and in long-term debt from the drawdown of currently undrawn revenue bond proceeds. Short-term borrowings are expected to fluctuate during this forecast period. Additional debt and/or equity financing may be required for various reasons, including increases in the costs of or an acceleration of the construction of capital projects, unbudgeted acquisitions or investments in new businesses, 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 and other unanticipated expenditures not included in the 2004 through 2008 forecast. 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 2004 through 2008 are currently estimated to total $760 million. Approximately 52% of forecast gross capital expenditures (which includes the allowance for funds used during construction and capital expenditures funded by third-party contributions in aid of construction) is for transmission and distribution projects and 36% for generation projects, with the remaining 12% for general plant.

For 2004, electric utility net capital expenditures are estimated to be $194 million. Gross capital expenditures are estimated to be $216 million, including approximately $102 million for transmission and distribution projects, approximately $88 million for generation projects and approximately $26 million for general plant and other projects. Investment in renewable projects through RHI in 2004 is estimated to be an additional $1 million. Drawdowns of $2 million of proceeds from the sale of Series 2002A tax-exempt special purpose revenue bonds, cash flows from operating activities and short-term borrowings are expected to provide the cash needed for the net capital expenditures in 2004.

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 and CHP installations, the effects of opposition to proposed construction projects and requirements of environmental and other regulatory and permitting authorities.

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Bank

(in millions)	September 30, 2004		December 31, 2003		% change
Total assets	$	6,680	$	6,515	3	%
Available-for-sale investment and mortgage-related securities		2,915		2,717	7
Held-to-maturity investment securities		97		95	3
Loans receivable, net		3,126		3,122	—
Deposit liabilities		4,182		4,026	4
Securities sold under agreements to repurchase		791		831	(5	)
Advances from Federal Home Loan Bank		1,020		1,017	—

As of September 30, 2004, ASB was the third largest financial institution in Hawaii based on total assets of $6.7 billion and deposits of $4.2 billion.

ASB’s principal sources of liquidity are customer deposits, borrowings, the sale of mortgage loans into secondary market channels and the maturity and repayment of portfolio loans and mortgage-related securities. ASB’s principal sources of borrowings are advances from the FHLB and securities sold under agreements to repurchase from broker/dealers. ASB is approved to borrow from the FHLB up to 35% of ASB’s assets to the extent it provides qualifying collateral and holds sufficient FHLB stock. At September 30, 2004, ASB’s unused FHLB borrowing capacity was approximately $1.3 billion. ASB utilizes growth in deposits, advances from the FHLB and securities sold under agreements to repurchase to fund maturing and withdrawable deposits, repay maturing borrowings, fund existing and future loans and make investments. At September 30, 2004, ASB had commitments to borrowers for undisbursed loan funds and unused lines and letters of credit of $1.0 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 2004, net cash provided by ASB’s operating activities was $85 million. Net cash used in ASB’s investing activities was $213 million, due to the purchase of mortgage-related securities, net of repayments and sales, partly offset by repayments of loans, net of originations and purchases. Net cash provided by financing activities was $97 million largely due to a net increase of $156 million in deposit liabilities and $3 million in advances from the FHLB, partly offset by a net decrease of $44 million in securities sold under agreements to repurchase and the payment of $19 million in common and preferred stock dividends.

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, 2004, ASB was well-capitalized (ratio requirements noted in parentheses) with a leverage ratio of 7.0% (5.0%), a Tier-1 risk-based capital ratio of 14.5% (6.0%) and a total risk-based capital ratio of 15.5% (10.0%).

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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; interest-rate environment; 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 24 to 31 of HEI’s 2003 Annual Report and pages 60 to 64 of 2003 Form 10-K/A (in HECO’s 2003 Management’s Discussion and Analysis of Financial Condition and Results of Operations).

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; property, plant and equipment; pension and other postretirement benefit obligations; contingencies and litigation; income taxes; regulatory assets and liabilities; electric utility revenues; allowance for loan losses; and reserves for discontinued operations. For example, in the second quarter of 2004, a significant change in estimated income taxes occurred. As a result of the Tax Appeal Court’s decision, ASB wrote off the deposit for assessed bank franchise taxes recorded in June 2003 and expensed the related bank franchise taxes and interest for subsequent periods through March 31, 2004 related to the REIT, resulting in a cumulative charge to net income in the second quarter of 2004 of $21 million for the bank franchise taxes.

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 31 to 35 of HEI’s 2003 Annual Report and pages 64 to 67 of HEI and HECO’s Annual Report on Form 10-K/A for 2003 (in HECO’s 2003 Management’s Discussion and Analysis of Financial Condition and Results of Operations).

Item 3. Quantitative and qualitative disclosures about market risk

The Company manages various risks in the ordinary course of business, including credit risk and liquidity risk (see “Results of operations—Bank” and “Liquidity and capital resources” in “Management’s discussion and analysis of financial condition and results of operations”). The Company is not exposed to significant market risk from trading activities because the Company does not have a portfolio of trading assets. The Company is exposed to some commodity price risk primarily related to its fuel supply and IPP contracts. The Company’s commodity price risk is mitigated by the electric utilities’ energy cost adjustment clauses in their rate schedules. The Company currently has no hedges against its commodity price 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 35 to 38 of HEI’s 2003 Annual Report.

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ASB’s interest-rate risk sensitivity measures as of September 30, 2004 and December 31, 2003 constitute “forward-looking statements” and were as follows:

	September 30, 2004						December 31, 2003
	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	(7.6	)%	6.74	%	(371	)	(5.8	)%	6.30	%	(345	)
+200	(4.8	)	8.16		(229	)	(3.2	)	7.63		(212	)
+100	(1.9	)	9.47		(98	)	(0.9	)	8.82		(93	)
Base	—		10.45		—		—		9.75		—
-100	(4.8	)	10.72		27		(4.3	)	10.24		49

Management believes that ASB’s interest rate risk position at September 30, 2004 represents a reasonable level of risk. The analysis shows ASB’s NII profile as of September 30, 2004 to be slightly more sensitive to rising interest rates than in the December 31, 2003 analysis. The change in ASB’s NII profile from December 31, 2003 to September 30, 2004 is primarily due to the change in the shape of the yield curve, which resulted in slightly slower prepayment expectations. From December 31, 2003 to September 30, 2004, the yield curve flattened, as short term interest rates rose, while longer term interest rates fell slightly. The September 30, 2004 NII profile shows the balance sheet to be “liability-sensitive” in all rising interest rate scenarios. This is because as interest rates rise, the overall rate on liabilities increases faster than the overall rate on ASB’s assets. In rising interest rate environments, an expectation of slower prepayment speeds reduces the runoff of the existing mortgage assets, which reduces the amount available for reinvestment at the higher market rates. This constrains the speed with which the yield on the mortgage assets can adjust upwards to market levels. At the same time, the cost of the liabilities is projected to increase with each increase in the level of rates. As a result, NII falls in each of the rising rate scenarios.

In the –100 basis point scenario, NII drops relative to the base case because expectations of faster mortgage prepayments and lower reinvestment rates cause the yield on mortgage assets to decline faster than in the base case. The cost of the liabilities, however, does not fall as much because the low level of interest rates limits the ability to lower the rate on retail deposits, causing NII to fall. In this analysis, one of the modeling assumptions which impacts the magnitude of the change in NII in response to both rising and falling interest rates is the assumption about the speed and magnitude with which the rate on ASB’s core deposits change in response to changes in the overall level of interest rates.

ASB’s base NPV ratio as of September 30, 2004 was higher than on December 31, 2003, primarily a result of the change in the shape of the yield curve.

ASB’s NPV ratio sensitivity measures as of September 30, 2004 were essentially unchanged from December 31, 2003.

The computation of the prospective effects of hypothetical interest rate changes on the NII sensitivity, NPV ratio, and NPV ratio sensitivity analyses is based on numerous assumptions, including relative levels of market interest rates, loan prepayments, balance changes and pricing strategies, and should not be relied upon as indicative of actual results. To the extent market conditions and other factors vary from the assumptions used in the simulation analysis, actual results may differ materially from the simulation results. Furthermore, NII sensitivity analysis measures the change in ASB’s twelve-month, pre-tax NII in alternate interest rate scenarios, and is intended to help management identify potential exposures in ASB’s current balance sheet and formulate appropriate strategies for managing interest rate risk. The simulation does not contemplate any actions that ASB management might undertake in response to changes in interest rates. Further, the changes in NII vary in the twelve-month simulation period and are not necessarily evenly distributed over the period. These analyses are for analytical purposes only and do not represent management’s views of future market movements, the level of future earnings, or the timing of any changes in earnings within the twelve month analysis horizon. The actual impact of changes in interest rates on NII

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will depend on the magnitude and speed with which rates change, as well as management’s responses to the changes in interest rates.

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, 2004. Based on their evaluations, as of September 30, 2004, 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 Tayne S. Y. Sekimura, HECO Chief Financial Officer, have evaluated the disclosure controls and procedures of HECO as of September 30, 2004. Based on their evaluations, as of September 30, 2004, 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 2. Unregistered sales of equity securities and use of proceeds

(c) Purchases of HEI common shares were made as follows:

ISSUER PURCHASES OF EQUITY SECURITIES

Period*	(a) Total Number of Shares Purchased**	(b) Average Price Paid per Share**		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
July 1 to 31, 2004	159,926	$	25.91	—	NA
August 1 to 31, 2004	102,041		25.51	—	NA
September 1 to 30, 2004	302,176		26.31	—	NA
	564,143	$	26.05	—	NA

NA Not applicable.

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

** The purchases were made to satisfy the requirements of the DRIP and HEIRSP for shares purchased for cash or by the reinvestment of dividends by participants under those plans and none of the purchases were made under publicly announced repurchase plans or programs. Average prices per share are calculated exclusive of any commissions payable to the brokers making the purchases for the DRIP and HEIRSP. Of the shares listed in column (a), 138,126 of the 159,926 shares, 80,541 of the 102,041 shares and 267,476 of the 302,176 shares were purchased for the DRIP and the remainder were purchased for the HEIRSP.

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Item 5. Other information

(a) 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,		Years ended December 31,
2004	2003	2003	2002	2001	2000	1999
2.37	2.01	2.11	2.03	1.82	1.76	1.83

Ratio of earnings to fixed charges including interest on ASB deposits

Nine months ended September 30,		Years ended December 31,
2004	2003	2003	2002	2001	2000	1999
2.05	1.76	1.84	1.72	1.52	1.49	1.50

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) in 2003 and prior years when the trust subsidiaries were consolidated, the preferred securities distribution requirements of trust subsidiaries.

HECO and Subsidiaries

Ratio of earnings to fixed charges

Nine months ended September 30,		Years ended December 31,
2004	2003	2003	2002	2001	2000	1999
3.79	3.23	3.36	3.71	3.51	3.39	3.09

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) in 2003 and prior years, when the trust subsidiaries were consolidated, the preferred securities distribution requirements of the trust subsidiaries.

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B. 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 propose 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 on Oahu, 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.

In February 2004, HECO conducted an updated long-term sales and peak forecast for Oahu that projects increased system peak requirements based on the island’s strengthening economy. Based on this forecast, HECO supplied information to the PUC in its annual Adequacy of Supply letter, filed on March 31, 2004. This letter concluded that HECO’s generation capacity for Oahu for the next three years (2004-2006) is sufficiently large to meet all reasonably expected demands for service if there is expeditious review and approval of the DSM load management programs and of either the CHP Program currently pending before the PUC or individual CHP contracts proposed to the PUC. The letter also concluded that, since additional firm capacity from new central station generation is not likely to be installed before 2009, if the higher forecast for system peak demand does occur, there is an increased risk to generation system reliability by or before 2006 and beyond if other measures, such as DSM, distributed generation, combined heat and power or other firm capacity supply-side resources, fall short of achieving their forecast benefits or are otherwise insufficient to reduce or meet the forecast peak demand. The Adequacy of Supply letter points out that should the process for the third IRP find that the timing, characteristics or size of the next increment of generation capacity are different from those identified in the letter, that the circumstances will be examined at that time to determine the appropriate course of action.

In October 2004, the PUC approved HECO’s DSM load management programs, and commencement of the implementation of the programs is scheduled for the beginning of 2005, instead of 2004 (as assumed in the February 2004 forecast). New larger energy efficient DSM programs were developed during the on-going IRP process, and approval will be sought in the rate case to be filed pursuant to the DSM stipulation (although HECO also plans to seek approval on a more accelerated basis if possible). On the supply-side, CHP system installations are behind schedule, due to suspension of the CHP program application pending the generic DG docket, but HECO sought PUC approval in October 2004 of a CHP system for a customer and will seek PUC approval for future contracts on a case-by-case basis. Also on the supply-side, HECO and Kalaeloa executed amendments to the Kalaeloa PPA, subject to certain conditions including PUC approval, under which Kalaeloa would provide up to 29 MW of additional firm capacity.

Demand for electricity on Oahu continues to increase. An all-time peak demand of 1,327 MW (gross) was recorded on October 12, 2004, and was 14 MW higher than the projected peak for 2004 in the February 2004 forecast. As a result of HECO’s units running harder and getting older, the availability rates for the units have declined somewhat, even though they remain better than the industry averages for similar units. On October 13, 2004, HECO issued a public request that its customers voluntarily conserve energy as two units were out for scheduled maintenance and two units were unexpectedly unavailable.

C. Proposed air quality regulations

HECO recently submitted comments to the EPA on two proposed air quality regulations: the EPA’s proposal to regulate nickel emissions from oil-fired steam utility units and the proposed revisions to the rule designed to control haze at National Parks. Regarding the proposed nickel emissions regulation, HECO commented that the EPA’s assumptions underlying the proposal greatly overestimated risk associated with nickel emissions, existing utility units could not reliably meet the proposed emission standard even when employing the default control technology upon which the EPA based the proposed standards, and island utilities such as HECO would need a longer period of time

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to comply with the regulations if adopted. Management believes that, if adopted as currently proposed, the EPA’s proposal to regulate nickel emissions from oil-fired boilers may require capital investments for HECO’s steam generating units in amounts which may be significant. The EPA has announced that it intends to promulgate final regulations by March 2005. Regarding the regional haze proposal, HECO commented that the regulations should take into account natural sources of haze such as Kilauea Volcano and suggested that the agency specifically approve specified air quality emissions models in addition to the ones identified in the proposed rule. Management believes the regional haze control rules, if adopted as currently proposed, may require installation of costly Best Available Retrofit Technology on one or more generating units operated by the utilities. Due to the complexity of the current proposal to control haze impacts and the latitude that states will be granted in applying the proposed regulation, management is unable to determine, at this time, to which utility generating units, if any, the rule will apply or the cost of compliance, which could be significant.

D. MECO’s IRP

MECO’s second IRP, filed in May 2000, identified changes in key forecasts and assumptions since the development of MECO’s initial IRP. On the supply side, MECO’s second IRP focused on the planning for the installation of approximately 150 MW of additional generation through the year 2020 on the island of Maui, including 38 MW of generation at its Maalaea power plant site in increments from 2000-2005. MECO completed the installation of a 20 MW increment (the second) at Maalaea in September 2000. In August 2004, MECO received the necessary air permit, effective September 8, 2004, for the final increment of 18 MW, which was originally expected to be installed in 2005, and is currently expected to be installed in the third quarter of 2006.

E. Wind monitoring at HECO’s Kahe power plant

In April 2004, HECO began a one-year study to monitor wind speed, direction and turbulence on the ridges above the company’s Kahe power plant. High-resolution wind resource maps indicated that the ridges above Kahe have one of Oahu’s strongest wind resources, and the study is being conducted to confirm the area’s potential to generate electricity with wind. At the end of the year-long study, a wind energy project may be considered for the site if the on-site monitoring yields positive results and surrounding community concerns, if any, about such a project can be satisfactorily addressed.

F. Honolulu Power Plant/Waterfront Redevelopment

The State of Hawaii is considering a development proposal to extensively redevelop the Honolulu Harbor. Included in that proposal is the relocation of the Honolulu Power Plant to an unspecified location.

In discussions with the State, HECO has stated its willingness to relocate the plant if all siting, permitting and financing issues are addressed so as to provide seamless substitute generation capacity to the electric system and continued reliability for its customers.

G. City and County sewer line

On July 22, 2004, a contractor hired by HECO for a utility line extension project to support the expansion of the City and County of Honolulu’s wastewater treatment plant accidentally drilled into a force main sewer line owned by the City and County. Management believes HECO has defenses against any assertions that it has liability for the incident as well as insurance coverage (over a deductible amount). An investigation is ongoing and discussions by HECO with the City and County to resolve potential liability issues are continuing. HECO has increased its general liability reserves to provide for clean-up costs for which it may have responsibility with respect to this incident in the third quarter of 2004. The City and County, with HECO’s cooperation, is developing a plan to repair the force main.

H. Amendments to Power Purchase Agreement between Kalaeloa Partners, L.P. and HECO

In October 1988, HECO entered into an agreement with Kalaeloa, a limited partnership. The agreement with Kalaeloa, as last amended on October 1, 1999 and approved by the PUC (the agreement), provides that HECO will purchase 180 MW of firm capacity for a period of 25 years beginning in May 1991. On October 12, 2004, Kalaeloa and HECO executed two amendments to the agreement (amendments) which may result in an additional 29 MW of firm capacity being made available to HECO by the summer of 2005. Each of the amendments is subject to the satisfaction of certain conditions, including issuance by the PUC of an acceptable order which, among other things,

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approves the amendment and orders that HECO may recover the costs resulting from the amendments in HECO’s electric rates. The amendments are filed herein as HECO Exhibits 10.3 and 10.4.

I. American Savings Bank Select Deferred Compensation Plan (Restatement Effective January 1, 2005)

In November 2004, Constance H. Lau, President and Chief Executive Officer of ASB and a director of HEI, became a participant in the American Savings Bank Select Deferred Compensation Plan, which is filed herein as HEI Exhibit 10.1.

J. Issuance of Shares without Certificates

On October 26, 2004, HEI’s Board of Directors approved amendments to Articles XIII and XIV of HEI’s By-laws, and the restatement of the By-laws as thus amended, to authorize HEI to issue shares of its Common Stock evidenced by book-entry positions as an alternative to physical stock certificates. It is expected that the authorization will be used initially in connection with shares of HEI common stock issued under the DRIP and HEIRSP, but the book-entry system may be expanded to other issuances and stock transfers in the future. Also on October 26, 2004, the HEI Board of Directors approved the Second Amendment to the Rights Agreement between HEI and Continental Stock Transfer & Trust Company, as Rights Agent, to (a) make necessary conforming changes to provide that the Rights that attach to shares of Common Stock issued without certificates are evidenced by the book-entry positions that evidence those shares and (b) make changes to the summary description of the Rights (attached as Exhibit C to the Second Amendment), primarily to encompass the issuance of shares without certificates and to reflect the effects of the 2-for-1 stock split completed on June 10, 2004. The amended and Restated By-laws and the Second Amendment to the Rights Agreement are included in this filing as Exhibits 3(ii) and 4, respectively, through incorporation by reference of these exhibits as filed with the Current Report on Form 8-K filed by HEI on October 26, 2004.

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Item 6. Exhibits

HEI Exhibit 3(ii)	Amended and Restated Bylaws of Hawaiian Electric Industries, Inc. (incorporated by reference to Exhibit 3(ii) to HEI’s Current Report on Form 8-K dated October 26, 2004, File No. 1-8503)
HEI Exhibit 4	Second Amendment to Rights Agreement, dated as of October 26, 2004, between Hawaiian Electric Industries, Inc. and Continental Stock Transfer & Trust Company, as Rights Agent (incorporated by reference to Exhibit 4 to HEI’s Current Report on Form 8-K dated October 26, 2004, File No. 1-8503)
HEI Exhibit 10.1	American Savings Bank Select Deferred Compensation Plan (Restatement Effective January 1, 2005)
HEI Exhibit 10.2	Form of Hawaiian Electric Industries, Inc. Stock Appreciation Right Agreement with Dividend Equivalents
HEI Exhibit 12.1	Hawaiian Electric Industries, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, nine months ended September 30, 2004 and 2003 and years ended December 31, 2003, 2002, 2001, 2000 and 1999
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
HECO Exhibit 10.3	Confirmation Agreement Concerning Section 5.2B(2) of Power Purchase Agreement and Amendment No. 5 to Power Purchase Agreement between HECO and Kalaeloa Partners, L.P., dated October 12, 2004
HECO Exhibit 10.4	Agreement for Increment Two Capacity and Amendment No. 6 to Power Purchase Agreement between HECO and Kalaeloa Partners, L.P., dated October 12, 2004
HECO Exhibit 12.2	Hawaiian Electric Company, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, nine months ended September 30, 2004 and 2003 and years ended December 31, 2003, 2002, 2001, 2000 and 1999
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 Tayne S. Y. Sekimura (HECO Chief Financial Officer)
HECO Exhibit 32.3	Written Statement of T. Michael May (HECO Chief Executive Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002
HECO Exhibit 32.4	Written Statement of Tayne S. Y. Sekimura (HECO Chief Financial Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002

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SIGNATURES

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

HAWAIIAN ELECTRIC INDUSTRIES, INC.		HAWAIIAN ELECTRIC COMPANY, INC.
	(Registrant)		(Registrant)
By	/S/    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/    TAYNE S. Y. SEKIMURA
	Eric K. Yeaman Financial Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer of HEI)		Tayne S. Y. Sekimura 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 5, 2004		Date: November 5, 2004

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