10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 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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EX-10.1

HEI Exhibit 10.1

AMERICAN SAVINGS BANK

SELECT DEFERRED COMPENSATION PLAN

(Restatement Effective January 1, 2005)

ARTICLE 1. INTRODUCTION

1.1 Establishment and Purpose of the Plan. AMERICAN SAVINGS BANK, F.S.B. (the “Bank”), hereby restates the American Savings Bank Executive Security Plan as the American Savings Bank Select Deferred Compensation Plan (the “Plan”). Except as otherwise noted, this restatement is effective as of the Plan Year commencing January 1, 2005. The Plan was originally effective May 1, 2000.

1.2 Purpose of Plan. The purpose of the Plan is to provide Participants an opportunity to defer compensation that would otherwise be currently payable to them. The Plan is intended to be an unfunded plan for a select group of management or highly compensated employees within the meaning of Sections 201(2), 301(a)(3), and 401(a)(1) of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”).

ARTICLE 2. DEFINITIONS

2.1 For purposes of this Plan, unless otherwise clearly apparent from the context, the following phrases or terms shall have the meanings indicated:

(a) “Account Balance” shall mean, as of any given date called for under the Plan, the balance of the Participant’s Deferral Contribution Account as such account has been adjusted to reflect all applicable Investment Adjustments and all prior withdrawals and distributions, in accordance with Article 4 of the Plan.

(b) “Bank” shall mean American Savings Bank, F.S.B., and any successor.

(c) “Base Annual Compensation” shall mean the base annual compensation payable to an employee by the Bank for services rendered during a Plan Year and required to be set forth in Box 1 of the employee’s W-2 for the Plan Year before reduction for any Elective Deductions and including commissions, provided, however, that Base Annual Compensation shall not include any Bonus paid during or with respect to a Plan Year, contributions to any employee benefit plan (other than Elective Deductions), stock options, amounts paid under the Hawaiian Electric Industries, Inc. Long-Term Incentive Plan, amounts paid to or on behalf of the employee for “fringe benefits” such as (but not limited to) group life

and health insurance, automobile allowance, club memberships and dues, or expense reimbursements, regardless of whether such benefits may or may not be taxable to the employee, or “imputed income,” including, but not limited to, employee income arising from relief from indebtedness or employer payment of taxes or other obligations of the employee.

(d) “Beneficiary” shall mean one or more persons, trusts, estates or other entities, designated by the Participant in accordance with Article 11, to receive the Participant’s undistributed Account Balance, in the event of the Participant’s death.

(e) “Beneficiary Designation Form” shall mean the document which shall be used by the Participant to designate the Participant’s Beneficiary for the Plan.

(f) “Benefit Distribution Date” shall mean the date distribution of the Participant’s Account Balance is triggered and shall be the date on which the Participant’s employment terminates for any reason whatsoever, including, but not limited, to death, Retirement, Disability or any other reason. In the event the Benefit Distribution Date is triggered due to: (i) Termination of Employment, as such term is defined in Section 2.1(am), the Participant’s Account Balance shall be payable pursuant to Article 7; (ii) Retirement, as such term is defined in Section 2.1(ai), the Participant’s Account Balance shall be payable pursuant to Article 8; (iii) pre-retirement death, the Participant’s Account Balance shall be payable pursuant to Article 9; and (iv) Disability, as such term is defined in Section 2.1(p), the Participant’s Account Balance shall be payable pursuant to Article 10.

(g) “Board of Directors” shall mean the board of directors of the Bank.

(h) “Bonus” shall mean amounts payable to a Participant during a Plan Year under any bonus or incentive plan or arrangement sponsored by the Employer, before reduction for any Elective Deductions, but excluding commissions, stock-related awards and other non-monetary incentives, and such other incentive items as may be excluded from the definition of “Bonus” by the Committee in its sole discretion.

(i) “Change in Control” shall mean the earliest to occur of the following events:

(1) The consummation of any transaction or series of transactions as a result of which any “Person” (as the term, “person,” is used for purposes of Section 13(d) or 14(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)), other than an “Excluded Person” (as hereinafter defined), has or obtains ownership or control, directly or indirectly, of fifty percent (50%) or

2

more of the combined voting power of all securities of the Bank or any successor or surviving corporation of any merger, consolidation or reorganization involving the Bank (the “Voting Securities”). The term “Excluded Person” means any one or more of the following: (i) the Bank or any majority-owned subsidiary of the Bank, (ii) an employee benefit plan (or a trust forming a part thereof) maintained by (A) the Bank or (B) any majority-owned subsidiary of the Bank, (iii) any Person who as of the initial effective date of this Plan owned or controlled, directly or indirectly, ten percent (10%) or more of the then outstanding Voting Securities, or any individual, entity or group that was part of such a Person;

(2) A merger, consolidation or reorganization involving the Bank as a result of which the holders of Voting Securities immediately before such merger, consolidation or reorganization do not immediately following such merger, consolidation or reorganization own or control, directly or indirectly, at least fifty percent (50%) of the Voting Securities in substantially the same proportion as their ownership or control of the Voting Securities immediately before such merger, consolidation or reorganization; or

(3) The sale or other disposition of all or substantially all of the assets of the Bank to any Person (other than to a majority-owned subsidiary of the Bank).

(j) “Claimant” shall mean the person or persons described in Section 15.1 who apply for benefits or amounts that may be payable under the Plan.

(k) “Code” shall mean the Internal Revenue Code of 1986, as amended. References to the Code shall include references to any successor section or provision of the Code.

(l) “Committee” shall mean the committee described in Article 13, which shall administer the Plan.

(m) “Contributions” shall collectively refer to any and all Deferral Contributions as such term has been defined herein.

(n) “Deferral Contribution” shall mean the aggregate amount of Base Annual Compensation and Bonus deferred by a Participant with respect to a Plan Year in accordance with the terms of the Plan and the Participant’s Election Form and “credited” to the Participant’s Deferral Contribution Account. Deferral Contributions shall be deemed to be made to the Plan by the Participant on the date the Participant would have received such compensation had it not been deferred pursuant to the Plan and shall be allocated to Hypothetical Investments pursuant to the Participant’s then

3

effective Investment Allocation or Investment Re-Allocation Form as soon as administratively feasible.

(o) “Deferral Contribution Account” shall mean an account to record a Participant’s aggregate Deferral Contributions, as well as any appreciation (or depreciation) specifically attributable to such Deferral Contributions due to Investment Adjustments, reduced to reflect all prior distributions and withdrawals. The Deferral Contribution Account shall be utilized solely as a device for the measurement of amounts to be paid to the Participant under the Plan. The Deferral Contribution Account shall not constitute or be treated as an escrow, trust fund, or any other type of funded account for Code or ERISA purposes and, moreover, contingent amounts credited thereto shall not be considered “plan assets” for ERISA purposes. The Deferral Contribution Account merely provides a record of the bookkeeping entries relating to the contingent benefits that the Employer promises to pay to a Participant and shall thus constitute merely an unsecured promise to pay such amounts in the future.

(p) “Disability” shall mean a period of disability during which a Participant qualifies for total permanent disability benefits under the Bank’s long-term disability plan, or, if a Participant does not participate in such a plan, a period of disability during which the Participant would have qualified for total permanent disability benefits had the Participant been a participant in such a plan, as determined by the Committee in its sole discretion. If the Bank does not sponsor such a plan, or discontinues to sponsor such a plan, Disability shall be determined by the Committee in its sole discretion, provided that a medical opinion that the Participant is totally and permanently disabled shall be deemed rebuttably correct.

(q) “Disability Benefit” shall mean the benefit set forth in Article 10.

(r) “Early Retirement” shall mean retirement upon the attainment of age 55 and before normal retirement age.

(s) “Election Form” shall mean the document required by the Committee to be submitted by a Participant, on a timely basis, which specifies (i) the amount of Base Annual Compensation and/or Bonus the Participant has elected to defer with respect to a Plan Year, (ii) the portion (if any) of such Deferral Contributions which shall be distributable upon an Interim Distribution Date rather than the Benefit Distribution Date, and (iii) the manner in which the Participant elects to have such Deferral Contributions distributed in the event such distribution is triggered by the Participant’s Retirement from the Bank. The Participant may elect to receive the Retirement Benefit in a lump sum or in substantially equal annual payments over a period not to exceed fifteen (15) years. An Election Form shall only be effective with respect to (i) Base Annual Salary earned

4

after the effective date of the Election Form and (ii) Bonus not yet ascertainable and declared by the Employer as of the effective date of the Election Form. In the event a Participant fails to submit an Election Form with respect to a Plan Year or fails to submit such form on a timely basis, the Participant shall not have Deferral Contributions during the Plan Year. A Participant may not make or change an Election Form after the commencement of the Plan Year to which it applies (or, in the case of the Plan’s first year or a Participant’s first becoming eligible, the portion of the Plan Year to which it applies), except as may be permitted pursuant to Articles 5 and 6.

(t) “Elective Deductions” shall mean those deductions from a Participant’s Base Annual Salary or Bonus for amounts voluntarily deferred by the Participant pursuant to any qualified or non-qualified deferred compensation or welfare or fringe benefit plan, including, without limitation, amounts deferred pursuant to Code Section 125, 132(f), 402(e)(3) and 402(h), provided, however, that all such amounts would have been payable to the Participant in cash had there been no such deferral and provided, further, that such amounts shall not include ASB Dollars, HEI FlexCredits or similar items of value.

(u) “Employer” shall mean the Bank and any subsidiary that has been selected by the Board of Directors to participate in the Plan and has adopted the Plan.

(v) “Enrollment Forms” shall mean the Participation Agreement, the Election Form, the Investment Allocation and Re-Allocation Forms, the Retirement Benefit Distribution Form and any other forms or documents which may be required of a Participant by the Committee, in its sole discretion, prior to and as a condition of participating in the Plan.

(w) “ERISA” shall mean the Employee Retirement Income Security Act of 1974, as amended. References herein to any section of ERISA shall include references to any successor section or provision of ERISA.

(x) “Highly Compensated Employee” with respect to a Plan Year (the “Eligibility Year”) shall mean an employee whose W-2 compensation for the preceding Plan Year is equal to at least 120% of the taxable wage base for that year and whose compensation is not expected to decline below 120% of the taxable wage base in the Eligibility Year. If the “preceding Plan Year” for purposes of the preceding sentence has not yet been completed, then W-2 compensation for the preceding Plan Year shall be projected, if necessary, on the basis of any reasonable method. For example, in the case of elections required to be made by continuing Participants prior to the first day of the Plan Year pursuant to Section 3.3(3), “Highly Compensated Employees” shall mean employees who, as

5

of the date of elections made pursuant to Section 3.3(3), either have earned or are reasonably projected to earn W-2 compensation that is equal to at least 120% of the taxable wage base for the year in which the elections are made and whose compensation is not expected to decline below 120% of the taxable wage base in the Eligibility Year. In the case of an employee who was or will have been employed for less than twelve months in the Plan Year preceding the Eligibility Year, the employee’s W-2 compensation shall be annualized by multiplying the employee’s actual or projected compensation for such year times a fraction, the denominator of which is the employee’s months of employment in the preceding Plan Year (including fractional months) and the numerator of which is twelve. In the case of an employee who was not employed by the Employer in the preceding Plan Year, the employee’s projected W-2 compensation from the Employer for the Eligibility Year and the taxable wage base for such year shall be employed for purposes of the rule stated in the first sentence of this section. An employee who is not otherwise a Highly Compensated Employee under this Section may nevertheless qualify as a Highly Compensated Employee with respect to a Plan Year if such employee’s average W-2 compensation over any period of prior Plan Years, not to exceed five, that includes the preceding Plan Year was at least 120% of the average taxable wage bases for such period. For purposes of this section, the following definitions shall apply:

(1) “W-2 compensation” shall mean the total compensation required to be set forth in Box 1 on the employee’s Form W-2 for a particular Plan Year, including, but not limited to, salary, commissions, and bonus, plus all elective contributions to arrangements qualifying under Section 125, 132(f), or 401(k) of the Code and all elective contributions to nonqualified deferred compensation arrangements within the meaning of Section 201(a) of ERISA, including contributions to this Plan.

(2) “Taxable wage base” shall mean the Old Age Survivors and Disability Insurance contribution and benefit base with respect to a year, as determined under section 230 of the Social Security Act.

Notwithstanding anything to the contrary in this Section, eligibility to participate in the Plan is not established merely by meeting the definition of “Highly Compensated Employee” but is subject to all provisions of Section 3.1, including Section 3.1(ii), which requires specific approval for participation by the Bank, in its sole discretion. The Committee may prescribe rules different from those stated in this Section 2.1(x) for the determination of “Highly Compensated Employee,” provided, however, that, in the reasonable opinion of the Committee, such rules satisfy the requirements of Sections 201(2), 301(a)(3), and 401(a)(1) of ERISA.

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(y) “Hypothetical Investment” shall mean an investment fund or benchmark made available to Participants by the Committee for the purpose of valuing Deferral Contribution Accounts.

(z) “Interim Distribution Date” shall mean the first day of a calendar year, selected by the Participant upon which the designated portion of Deferral Contributions attributable to a Plan Year (as well as any appreciation or depreciation of such amounts due to Investment Adjustments) shall be distributed in a lump sum payment. Notwithstanding the preceding sentence, in no event shall a Participant be permitted to select a date which is less than four (4) Plan Years from the effective date of the Election Form to which the Interim Distribution Date relates.

(aa) “Investment Adjustment(s)” shall mean any appreciation credited to (as income or gains) or depreciation deducted from (as losses) a Participant’s Deferral Contribution Account in accordance with such Participant’s selection of Hypothetical Investments pursuant to the Participant’s currently effective Investment Allocation Form or Investment Re-Allocation Form.

(ab) “Investment Allocation Form” shall mean a form prescribed by the Committee pursuant to which a Participant shall allocate new Deferral Contributions to Hypothetical Investments. Timely and proper completion and filing of an Investment Allocation Form is a condition for participating in the Plan. An Investment Allocation Form shall apply with respect to all new Deferral Contributions made to the Plan after the effective date of the Investment Allocation Form but prior to the timely filing of a subsequent Investment Allocation Form or Investment Re-Allocation Form. A new Investment Allocation Form may be filed by the Participant electronically, telephonically, in a writing on paper or by such other means as may be prescribed by the Committee, on a monthly or such other basis as the Committee may determine. Provided that such filing is timely and otherwise proper, it shall be given effect as soon as administratively feasible. An Investment Allocation Form shall be deemed timely if submitted to the Committee in accordance with the procedures and deadlines established by the Committee.

(ac) “Investment Re-Allocation Form” shall mean a form prescribed by the Committee pursuant to which a Participant may change the allocation to Hypothetical Investments both of the existing aggregate Deferral Contributions (including hypothetical appreciation or depreciation thereon) and of all new Deferral Contributions. An Investment Re-Allocation Form may be submitted by the Participant electronically, telephonically, or in a writing on paper or by such other means as may be prescribed by the Committee, on a monthly or such other basis as the Committee may determine. Provided that such filing is timely and otherwise proper, it shall

7

be given effect as soon as administratively feasible. An Investment Re-Allocation Form shall be deemed timely if submitted to the Committee in accordance with the procedures and deadlines established by the Committee.

(ad) “Management Employee” with respect to a Plan Year shall mean an employee, who, in the reasonable opinion of the Committee, possesses duties and responsibilities at management level and above. An employee at the level of Vice President and above shall be presumed to be a Management Employee for purposes of this definition so long as the employee possesses duties and responsibilities consistent with his or her title. Notwithstanding anything to the contrary in this Section, eligibility to participate in the Plan is not established merely by meeting the definition of “Management Employee” but is subject to all provisions of Section 3.1, including Section 3.1(ii), which requires specific approval for participation by the Bank, in its sole discretion. The Committee may prescribe rules different from those stated in this Section 2.1(ad) for the determination of “Management Employee,” provided, however, that, in the reasonable opinion of the Committee, such rules satisfy the requirements of Sections 201(2), 301(a)(3), and 401(a)(1)of ERISA.

(ae) “Participant” shall mean any employee (i) who is selected to participate in the Plan in accordance with Section 3.1, (ii) who elects to participate in the Plan, (iii) who signs and files the applicable Enrollment Forms (and other forms required by the Committee) on a timely basis, and (iv) whose signed Enrollment Forms (and other required forms) are accepted by the Committee. “Participant” shall also include a former employee entitled to receive benefits under the Plan.

(af) “Participation Agreement” shall mean the separate written agreement entered into by and between the Bank and the Participant, which shall indicate the Participant’s intent to defer compensation subject to the terms of the Plan and the Participation Agreement.

(ag) “Plan” shall mean the American Savings Bank Select Deferred Compensation Plan, as described herein, subject to amendment from time to time.

(ah) “Plan Year” shall mean the period beginning on January 1^st of each year and ending December 31^st.

(ai) “Retirement,” “Retires” or “Retired” shall mean, with respect to an Employee, Early Retirement or severance from employment on or after the attainment of age sixty-five (65) for any reason other than an authorized leave of absence, Disability, or death.

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(aj) “Retirement Benefit” shall mean the benefit set forth in Article 8.

(ak) “Select Group” for purposes of the phrase, “Select Group of Management or Highly Compensated Employees,” means a group of employees each of whom is a Management Employee or Highly Compensated Employee, who have been designated as eligible to participate in this Plan by the Committee pursuant to Section 3.1 hereof, and whose total number does not exceed twelve per cent (12%) of the Bank’s total workforce, considering all of such eligible employees and not only those who elect to participate in this Plan. Upon good cause and to the extent permissible under applicable law, including ERISA, the Committee may grant exceptions to the foregoing limitation on the total number of employees who may be designated as members of the Select Group, provided that the total number of employees so designated shall in no event exceed fifteen percent (15%) of the Bank’s total workforce or such other upper limit on participation as may be required by ERISA, U.S. Department of Labor or Treasury regulations, or judicial determination. The Committee, in its sole discretion, shall adopt whatever rules it may deem necessary, appropriate, or desirable to maintain the Select Group within the applicable size limitation, including, but not limited to, giving preference for eligibility to continuing Participants, Management Employees, or Highly Compensated Employees, or ranking employees within subgroups or within the Select Group by compensation, title, longevity, or any other variable deemed relevant by the Committee. For purposes of this section, “Bank’s total workforce” shall be broadly construed, including all common law, casual, contract, and leased employees. The Committee may prescribe rules different from those stated in this Section 2.1(ak) for the determination of “Select Group,” including in the event that this Plan is adopted by subsidiaries of the Bank, provided, however, that, in the reasonable opinion of the Committee, such rules satisfy the requirements of Sections 201(2), 301(a)(3), and 401(a)(1)of ERISA. Notwithstanding anything to the contrary in this Section, eligibility to participate in the Plan is not established merely by being includable in a “Select Group of Management or Highly Compensated Employees” but is subject to all provisions of Section 3.1, including Section 3.1(ii), which requires specific approval for participation by the Bank, in its sole discretion.

(al) “Termination Benefit” shall mean the benefit set forth in Article 7.

(am) “Termination of Employment” shall mean the voluntary or involuntary severing of employment for any reason other than Retirement, Disability, or death.

(an) “Trust” shall mean a grantor trust which meets the requirements of Revenue Procedure 92-64, 1992-2 C.B. 422, or successor authority and is commonly referred to as a “rabbi trust.”

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(ao) “Unforeseeable Emergency” shall mean a severe financial hardship to the Participant resulting from a sudden and unexpected illness or accident of the Participant or a spouse or dependent of the Participant, loss of the Participant’s property due to casualty, or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Participant. The circumstances that will constitute an Unforeseeable Emergency will depend upon the facts of each case, but an Unforeseeable Emergency shall not be deemed to exist to the extent that such hardship is or may be relieved

(1) through reimbursement or compensation by insurance or otherwise,

(2) by liquidation of the Participant’s assets, to the extent the liquidation of such assets would not itself cause severe financial hardship, or

(3) by cessation of Deferral Contributions under the Plan.

Examples of matters that are not Unforeseeable Emergencies include the need to send a Participant’s child to college or the desire to purchase a home. Withdrawals of amounts from a Participant’s Deferral Contribution Account because of an Unforeseeable Emergency may be permitted only to the extent reasonably needed to satisfy the emergency need. The circumstances that will constitute an Unforeseeable Emergency shall be determined by the Committee in its sole discretion in a manner consistent with Section 1.457-2(h)(4) and (5) of the Treasury Regulations.

ARTICLE 3. ELIGIBILITY, SELECTION, AND ENROLLMENT

3.1 Eligibility upon Selection by Committee. Employees who (i) are determined by the Bank to be includable in a Select Group of Management or Highly Compensated Employees of the Bank and (ii) are specifically approved for participation by the Bank, in its sole discretion, shall be eligible to participate in the Plan. Continued eligibility to participate in the Plan shall be conditioned upon a Participant’s continuing to meet the requirements of the Plan, including, but not limited to, continuing to be includable in a Select Group of Management or Highly Compensated Employees of the Bank.

3.2 Enrollment Requirements. Each Participant deemed eligible to participate in the Plan pursuant to Section 3.1, shall, as a condition to participating in the Plan, complete and return to the Committee all of the required Enrollment Forms, on a timely basis. In addition, the Committee shall, in its sole discretion, establish such other enrollment requirements necessary for continued participation in the Plan.

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3.3 Commencement of Participation. A Participant who has completed and filed Enrollment Forms within the time periods shown below, including, without limitation, an Election Form and Participation Agreement, shall participate in the Plan as of the following dates:

(1) With respect to the first year of the Plan: An eligible individual must complete and file Enrollment Forms within 30 days of the date on which the Plan is first effective and shall participate as of the first day of the month following the date on which the Participant files Enrollment Forms. Examples: (A) The Plan becomes effective May 1, 2000, and an eligible individual files Enrollment Forms prior to May 1, 2000. The individual participates as of May 1, 2000. (B) Same facts except that the individual files Enrollment Forms on or after May 1, 2000, but within 30 days of May 1, 2000. The individual participates as of June 1, 2000. (C) Same facts except that the individual fails to file Enrollment Forms within 30 days of May 1, 2000. The individual may not participate until the 2001 Plan Year.

(2) For New Participants: In the first year in which a Participant becomes eligible to participate in the Plan, the Participant must complete and file Enrollment Forms within 30 days of the date on which the Participant is first eligible and shall participate as of the first day of the month following the date on which the Participant files Enrollment Forms. Examples: (A) An individual becomes eligible to participate as of July 1, 2000, and files Enrollment Forms prior to July 1, 2000. The individual participates as of July 1, 2000. (B) Same facts except the individual files Enrollment Forms on or after July 1, 2000, but within 30 days of July 1, 2000. The individual participates as of August 1, 2000. (C) Same facts except the individual fails to file Enrollment Forms within 30 days of July 1, 2000. The individual may not participate until the 2001 Plan Year.

(3) For Continuing Participants: Continuing Participants must complete and file Enrollment Forms with respect to the next Plan Year within the time established by the Committee in its sole discretion, but in any event prior to the first day of the next Plan Year. Such Participants shall continue their participation in the Plan as of the first day of the next Plan Year. Examples: (A) A Participant files Enrollment Forms within the time period established by the Committee (which, in all events, shall be before the first day of the next Plan Year). The Participant participates as of the first day of the next Plan Year. (B) The Committee requires Enrollment Forms to be filed by December 31^st of a Plan Year. A Participant files Enrollment Forms on January 1^st of the next Plan Year. The Participant may not participate in the Plan in the next Plan Year.

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ARTICLE 4. DEFERRAL CONTRIBUTIONS, INVESTMENT ADJUSTMENTS, AND TAXES

4.1 Deferral Contributions.

(a) Election to Defer. A Participant may elect to defer amounts otherwise payable to the Participant with respect to a Plan Year as Base Annual Compensation or Bonus by completing and filing a Participation Agreement, annual Election Form, and any other Enrollment Forms that may be required by the Committee within the time periods shown in Section 3.3, above. Amounts deferred by a Participant with respect to a Plan Year shall be referred to collectively as a Deferral Contribution and shall be credited to a Deferral Contribution Account established in the name of the Participant. In no case shall an Election Form be given any retroactive effect whatsoever or shall a Participant be permitted to defer income with respect to services already performed and for which compensation is due and ascertainable.

(b) Components of Deferral Contributions.

(1) Base Annual Compensation. A Participant may designate a fixed dollar amount or a percentage to be deducted from his or her Base Annual Compensation. Such amount shall be deemed deducted after all Elective Deductions and shall be withheld, in substantially equal installments, from each regularly scheduled payment of Base Annual Compensation.

(2) Bonus. A Participant may designate a fixed dollar amount or a percentage to be deducted from the Participant’s Bonus. If a fixed dollar amount is designated by the Participant to be deducted from any Bonus payment and such fixed dollar amount exceeds the Bonus actually payable to the Participant (after taking into account Elective Deductions), the entire amount of the Bonus shall be withheld.

(c) Minimum Deferral.

(1) Minimum. During any Plan Year, the Committee may permit a Participant to defer, pursuant to an Election Form, one or more of the following forms of compensation in the following minimum amounts:

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Deferral	Minimum Amount
Base Annual Compensation	1	%
Bonus	1	%

If an Election Form is submitted which would yield less than the stated minimum amounts, the amount deferred shall be zero.

(2) Short Plan Year. If an individual first becomes a Participant after the first day of any Plan Year, the minimum deferral with respect to each of the items listed above shall be an amount equal to the product of the percentage set forth above and the amount payable with respect to an item over the remaining complete months of the Plan Year.

(d) Maximum Deferral. For any given Plan Year the Committee may permit a Participant to defer, pursuant to an Election Form, one or more of the following forms of compensation up to the following maximum percentages:

Deferral	Maximum Amount
Base Annual Compensation	100	%
Bonus	100	%

4.2 Selection of Hypothetical Investments. At the beginning of each Plan Year, the Committee shall provide each Participant with a list of Hypothetical Investments available. From time to time, in the sole discretion of the Committee, the Hypothetical Investments available within the Plan may be revised. A Participant’s Deferral Contributions with respect to a Plan Year shall be deemed invested in accordance with the Hypothetical Investments selected by the Participant pursuant to the Participant’s currently effective Investment Allocation or Re-Allocation Form. All Hypothetical Investment selections must be denominated in whole percentages unless otherwise permitted by the Committee. A Participant may make changes in selected Hypothetical Investments from time-to-time on a monthly or such other basis permitted by the Committee by means of completing and filing a new Investment Allocation Form or a new Investment Re-Allocation Form, in accordance with the policies and procedures of the Committee.

4.3 Adjustment of Participant Accounts. Although a Participant Deferral Contribution Account does not represent the Participant’s ownership of, or any ownership interest in, any particular assets, the Participant’s account shall be adjusted in accordance with the Hypothetical Investment(s) chosen by the Participant on his or her (i) Investment Allocation Form or (ii) Investment Re-Allocation Form, subject to the conditions and procedures set forth herein or established by the Committee from time to time. Any earnings generated under a Hypothetical Investment (such as interest and

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cash dividends and distributions) shall, at the Committee’s sole discretion, either be deemed to be reinvested in that Hypothetical Investment or reinvested in one or more other Hypothetical Investments designated by the Committee. A Participant’s Hypothetical Investments shall bear the reasonable and customary investment expenses and charges that are born by investments of a like character. All notional acquisitions and dispositions of Hypothetical Investments which occur within a Participant Deferral Contribution Account, pursuant to the terms of the Plan, shall be deemed to occur at such times as the Committee shall determine to be administratively feasible in its sole discretion and the Participant’s Deferral Contribution Account shall be adjusted accordingly. Accordingly, if a distribution or re-allocation must occur pursuant to the terms of the Plan and all or some portion of the Account Balance must be valued in connection with such distribution or re-allocation (to reflect Investment Adjustments), the Committee may in its sole discretion, unless otherwise provided for in the Plan, select a date or dates which shall be used for valuation purposes. Notwithstanding anything in this Plan to the contrary, any Investment Adjustments made to any Participants’ Deferral Contribution Accounts following a Change in Control shall be made in a manner no less favorable to Participants than the practices and procedures employed under the Plan, or as otherwise in effect, as of the date of the Change in Control.

4.4 Withholding of Taxes.

(a) Annual Withholding from Compensation. For any Plan Year in which Deferral Contributions are made to the Plan, the Employer shall withhold the Participant’s share of FICA and other employment taxes from the portion of the Participant’s Base Annual Compensation and/or Bonus not deferred. If deemed appropriate by the Committee, the Participant’s Election Form may be reduced in certain instances where necessary to facilitate compliance with applicable withholding requirements.

(b) Withholding from Benefit Distributions. The Bank (or the trustee of the Trust, as applicable) shall withhold from any payments made to a Participant under this Plan all federal, state and local income, employment and other taxes required to be withheld by the Employer (or the trustee of the Trust, as applicable) in connection with such payments, in amounts and in a manner to be determined in the sole discretion of the Employer (or the trustee of the Trust, as applicable).

4.5 Vesting. The Participant shall at all times be one hundred percent (100%) vested in all Deferral Contributions as well as in any appreciation (or depreciation) specifically attributable to such contributions due to Investment Adjustments.

ARTICLE 5. SUSPENSION OF DEFERRALS

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5.1 Unforeseeable Emergencies. If a Participant experiences an Unforeseeable Emergency, the Participant may petition the Committee to suspend any deferrals required to be made by the Participant pursuant to his or her current Election Form. The Committee shall determine, in its sole discretion, whether to approve the Participant’s petition. If the petition for a suspension is approved, suspension shall commence upon the date of approval and shall continue until the earlier of (i) the end of the Plan Year or (ii) the date the Unforeseeable Emergency ceases to exist, as determined by the Committee in its sole discretion.

5.2 Disability. From and after the date that a Participant is deemed to have suffered a Disability, any current Election Form of the Participant shall automatically be suspended and no further deferrals shall be required to be made by the Participant pursuant to his or her current Election Form.

5.3 Leave of Absence. If a Participant is authorized by the Bank for any reason to take an unpaid leave of absence from the employment of the Employer, the Participant’s deferrals shall be suspended until the earlier of the date the leave of absence expires or the Participant returns to a paid employment status. Upon such expiration or return, deferrals shall resume for the remaining portion of the Plan Year in which the expiration or return occurs, based on the Election Form, if any, made for that Plan Year. If no election was made for that Plan Year, no deferral shall be withheld. If a Participant is authorized by the Bank for any reason to take a paid leave of absence from the employment of the Employer, the Participant shall continue to be considered employed by the Employer and the appropriate amounts shall continue to be withheld from the Participant’s compensation pursuant to the Participant’s then current Election Form.

ARTICLE 6. INTERIM AND HARDSHIP DISTRIBUTIONS

6.1 Interim Distributions. A Participant may make an advance election, at the time an Election Form is filed for a Plan Year, to have certain amounts paid from the Deferral Contribution Account at an Interim Distribution Date designated by the Participant, instead of paid at the Participant’s Benefit Distribution Date. Such amount(s) shall be measured on the applicable Interim Distribution Date and shall be payable within thirty (30) days of such Interim Distribution Date. The Participant’s selection of an Interim Distribution Date must comply with Section 2.1(y). Notwithstanding a Participant’s advance election to designate an Interim Distribution Date, the amounts which would otherwise be subject to such Interim Distribution Dateshall be distributable upon the Participant’s Benefit Distribution Date (pursuant to Article 7, 8, 9 or 10, as applicable), if such date occurs prior to the Interim Distribution Date.

6.2 Withdrawal in the Event of an Unforeseeable Emergency. A Participant who believes he has experienced an Unforeseeable Emergency may request in writing

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a withdrawal of that portion of the Participant’s Deferral Contribution Account necessary to satisfy the emergency. The Committee shall determine, in its sole discretion, (i) whether an Unforeseeable Emergency has occurred and (ii) the amount reasonably required to satisfy the Unforeseeable Emergency, provided, however, that the withdrawal shall not exceed the Participant’s Account Balance. In making any determinations under this Section 6.2, the Committee shall be guided by the prevailing authorities under the Code, including, but not limited to, Section 1.457-2(h)(4) and (5) of the Treasury Regulations. If, subject to the sole discretion of the Committee, the petition for a withdrawal is approved, the distribution shall be made as soon as administratively feasible after approval by the Committee.

ARTICLE 7. TERMINATION BENEFIT

7.1 Termination Benefit. In the event the Participant’s Benefit Distribution Date is triggered due to his or her Termination of Employment (as such term is defined in Section 2.1(aj)), the Participant shall receive a Termination Benefit and no other benefits shall be payable under the Plan.

7.2 Payment of Termination Benefit. The Termination Benefit shall be a lump sum payment equal to the Participant’s Account Balance and shall be made no later than thirty (30) days after the occurrence of the Participant’s Benefit Distribution Date.

7.3 Death Prior to Payment of Termination Benefit. If a Participant dies after his or her Termination of Employment but before the Termination Benefit is paid, the Participant’s unpaid Termination Benefit shall be paid to the Participant’s Beneficiary in a lump sum.

ARTICLE 8. RETIREMENT BENEFIT

8.1 Retirement Benefit. In the event the Participant’s Benefit Distribution Date is triggered due to his or her Retirement or Early Retirement (as such terms are defined in Sections 2.1(r) and 2.1(ag)), the Participant shall receive the Retirement Benefit and no other benefit shall be payable under the Plan.

8.2 Payment of Retirement Benefit. The Retirement Benefit shall be payable in the form previously selected by the Participant, pursuant to his or her Retirement Benefit Distribution Form, and shall commence (or be fully paid, in the event a lump sum form of distribution was selected) no later than thirty (30) days after the occurrence of the Participant’s Benefit Distribution Date. The initial installment shall be based on the value of the Participant’s Account Balance, measured on his or her Benefit Distribution Date and shall be equal to 1/n (where ‘n’ is equal to the total number of annual benefit payments not yet distributed). Subsequent installment payments shall be computed in a consistent fashion, with the measurement date being the anniversary of the original measurement date.

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8.3 Death Prior to Completion of Retirement Benefit. If a Participant dies after Retirement but before the Retirement Benefit has commenced or been paid in full, the Participant’s unpaid Retirement Benefit payments shall be paid to the Participant’s beneficiary as elected by the Participant on the Benefit Distribution Election form.

ARTICLE 9. PRE-RETIREMENT DEATH BENEFIT

9.1 Pre-Retirement Death Benefit. In the event the Participant’s Benefit Distribution Date is triggered due to his or her death during employment, the Participant’s Beneficiary shall receive the pre-retirement death benefit described below and no other benefit shall be payable under the Plan.

9.2 Payment of Pre-Retirement Death Benefit. The pre-retirement death benefit shall be a payment equal to the Participant’s Account Balance payable as elected by the Participant on the Benefit Distribution Election form.

ARTICLE 10. DISABILITY BENEFIT

10.1 Disability Benefit. A Participant suffering a Disability shall receive a Disability Benefit equal to his or her Account Balance. Subject to Article 6, the Disability Benefit shall be paid in a lump sum within thirty (30) days of the Committee’s exercise of such right, provided, however, that should the Participant otherwise have been eligible to Retire, he or she shall be paid a Retirement Benefit in accordance with Article 8.

ARTICLE 11. BENEFICIARY DESIGNATION

11.1 Beneficiary. Each Participant shall have the right, at any time, to designate a Beneficiary or Beneficiaries to receive, in the event of the Participant’s death, those benefits payable under the Plan. The Beneficiary or Beneficiaries designated under this Plan may be the same as or different from the Beneficiary designation made under any other plan of the Employer.

11.2 Beneficiary Designation; Change. A Participant shall designate his or her Beneficiary by completing and signing a Beneficiary Designation Form, and returning it to the Committee or its designated agent. A Participant shall have the right to change his or her Beneficiary by completing, signing and submitting to the Committee a revised Beneficiary Designation Form in accordance with the Committee’s rules and procedures, as in effect from time to time. The submission of a new Beneficiary Designation Form shall constitute a revocation of all previously submitted Beneficiary Designation Forms. Facts as shown by the records of the Committee on the date of death shall be conclusive.

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11.3 Acknowledgment. No designation or change in designation of a Beneficiary shall be effective until received, accepted and acknowledged in writing by the Committee or its designated agent.

11.4 No Beneficiary Designation. If a Participant fails to designate a Beneficiary as provided above or if all designated Beneficiaries on the currently effective Beneficiary Designation Form predecease the Participant or die prior to complete distribution of the Participant’s benefits, then the Participant’s designated Beneficiary shall be deemed to be the Participant’s surviving spouse. If the Participant has no surviving spouse, the benefits remaining under the Plan shall be payable to the executor or personal representative of the Participant’s estate.

11.5 Discharge of Obligations. The payment of benefits under the Plan to a Beneficiary shall fully and completely discharge the Bank and the Committee from all further obligations under this Plan with respect to the Participant, and the Participant’s Participation Agreement shall terminate upon such full payment of benefits.

ARTICLE 12. TERMINATION, AMENDMENT OR MODIFICATION

12.1 Termination. Although the Bank anticipates that it will continue the Plan for an indefinite period of time, there is no guarantee that it will continue the Plan or will not terminate the Plan at some time in the future. Accordingly, the Bank reserves the right to discontinue its sponsorship of the Plan and to terminate the Plan, in its sole discretion, at any time, with or without notice, by action of its Board of Directors; similarly, each Employer other than the Bank adopting this Plan reserves the right to discontinue it, with or without notice, in its sole discretion, as to its own Employees. Upon the termination of the Plan (or the participation in the Plan by an Employer other than the Bank), all amounts credited to the Deferral Contribution Account of each affected Participant shall be 100% vested and taxable and shall be paid to the Participant or, in the case of a Participant’s death, to the Participant’s Beneficiary, in a lump sum notwithstanding any elections made by the Participant, and the Participation Agreements relating to the Participant’s Deferral Contribution Account shall terminate upon full payment of such Account Balance.

12.2 Amendment. The Bank may, at any time, with or without notice, amend or modify the Plan in whole or in part, in whatever respects it may deem necessary, appropriate or desirable, including, without limitation, by suspending acceptance of further deferrals under the Plan; provided, however, that (i) no amendment or modification shall be effective to decrease or restrict the value of a Participant’s Account Balance in existence at the time the amendment or modification is made, calculated as if the Participant had experienced a Termination of Employment as of the effective date of the amendment or modification, or, if the amendment or modification occurs after the date upon which the Participant was eligible to Retire, calculated as if the Participant had Retired as of the effective date of the amendment or modification, and (ii) except as specifically provided in Section 12.1, no amendment or modification shall be made after

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a Change in Control which adversely affects the vesting, calculation or payment of benefits hereunder or diminishes any other rights or protections any Participant or Beneficiary would have had, but for such amendment or modification, unless each affected Participant or Beneficiary consents in writing to such amendment. The Bank hereby delegates the authority to amend this Plan to the Committee.

12.3 Effect of Payment. The full payment of the applicable benefit under the provisions of the Plan shall completely discharge all obligations under this Plan to a Participant and the Participant’s designated Beneficiaries, and the Participation Agreement of such a Participant shall terminate.

ARTICLE 13. ADMINISTRATION

13.1 Committee Duties. This Plan shall be administered by a Committee which shall consist of the Board of Directors, or such committee as the Board of Directors shall appoint. Members of the Committee may be Participants under this Plan. The Committee shall also have the discretion and authority to (i) make, amend, interpret, and enforce all appropriate rules and regulations for the administration of this Plan and (ii) decide or resolve any and all questions including interpretations of this Plan, as may arise in connection with the Plan. Any individual serving on the Committee who is a Participant shall not vote or act on any matter relating solely to himself or herself. When making a determination or calculation, the Committee shall be entitled to rely on information furnished by a Participant or the Bank. This Section 13.1 shall not be interpreted to limit the authority of the Board of Directors to allocate specific responsibilities regarding the administration of the Plan to particular individuals, persons, committees, or other bodies.

13.2 Agents. In the administration of this Plan, the Committee may, from time to time, employ agents and delegate to them such administrative duties as it sees fit (including acting through a duly appointed representative) and may from time to time consult with counsel who may be counsel to any Employer.

13.3 Binding Effect of Decisions. The decision or action of the Committee with respect to any question arising out of or in connection with the administration, interpretation and application of the Plan and rules and regulations promulgated hereunder shall be final and conclusive and binding upon all persons having any interest in the Plan.

13.4 Indemnity of Committee. The Bank shall indemnify and hold harmless the members of the Committee, and any Employee to whom duties of the Committee may be delegated, against any and all claims, losses, damages, expenses or liabilities arising from any action or failure to act with respect to this Plan, except in case of willful misconduct by the Committee or any of its members or any such Employee.

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13.5 Employer Information. To enable the Committee to perform its functions, the Bank shall supply full and timely information to the Committee on all matters relating to the compensation of its Participants, the date and circumstances of the Retirement, Disability, death or Termination of Employment of its Participants, and such other pertinent information as the Committee may reasonably require.

ARTICLE 14. OTHER BENEFITS AND AGREEMENTS

14.1 The benefits provided for a Participant and the Participant’s Beneficiary under the Plan are in addition to any other benefits available to such Participant under any other plan or program for employees of the Bank. The Plan shall supplement and shall not supersede, modify or amend any other such plan or programs except as may otherwise be expressly provided.

ARTICLE 15. CLAIMS PROCEDURES

15.1 Presentation of Claim. Any Participant and any Beneficiary, Personal Representative or Executor of a deceased Participant (such Participant or Beneficiary being referred to below as a “Claimant”) may deliver to the Committee a written claim for a determination with respect to the amounts distributable to such Claimant from the Plan. If such a claim relates to the contents of a notice received by the Claimant, the claim must be made within sixty (60) days after such notice was received by the Claimant. All other claims must be made within one hundred eighty (180) days of the date on which the event that caused the claim to arise occurred. The claim must state with particularity the determination desired by the Claimant.

15.2 Decision on Claim. Within ninety (90) days after receipt of a claim, the Committee shall send to the Claimant written notice of the granting or denying, in whole or in part, of such claim, unless special circumstances require an extension of time for processing the claim. In no event may an extension exceed ninety (90) days from the end of the initial period. If such extension is necessary, the Claimant shall be given written notice to this effect prior to the expiration of the initial ninety (90) day period which shall specify the special circumstances requiring extension. If notice of the denial of a claim is not furnished in accordance with this Section, then the claim shall be deemed denied, and the Claimant shall be permitted to exercise the Claimant’s right to seek review pursuant to Sections 15.4 and 15.5.

15.3 Notification of Decision. The Committee shall consider a Claimant’s claim within a reasonable time, and shall notify the Claimant in writing:

(a) that the Claimant’s requested determination has been made, and that the claim has been allowed in full; or

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(b) that the Committee has reached a conclusion contrary, in whole or in part, to the Claimant’s requested determination, and such notice must set forth in a manner calculated to be understood by the Claimant:

(i) the specific reason(s) for the denial of the claim, or any part of it;

(ii) specific reference(s) to pertinent provisions of the Plan upon which such denial is based;

(iii) a description of any additional material or information necessary for the Claimant to perfect the claim and an explanation of why such material or information is necessary; and

(iv) an explanation of the claim review procedure set forth in Section 15.4 below.

15.4 Review of a Denied Claim. Within sixty (60) days after receiving a notice from the Committee that a claim has been denied, in whole or in part, a Claimant (or the Claimant’s duly authorized representative) may file with the Committee a written request for a review of the denial of the claim. Thereafter, but not later than thirty (30) days after the review procedure began, the Claimant (or the Claimant’s duly authorized representative)

(a) may review pertinent documents;

(b) may submit written comments or other documents; and/or

(c) may request a hearing, which the Committee, in its sole discretion, may grant.

15.5 Decision on Review. The Committee shall render its decision on review not later than sixty (60) days after the filing of a written request for review of the denial, unless a hearing is held or other special circumstances require additional time, in which case the Committee’s decision must be rendered within one hundred twenty (120) days after such date. If such extension is necessary, the claimant shall be given written notice of the extension prior to the expiration of the initial sixty (60) day period. If notice of the decision on the review is not furnished in accordance with this Section, then the claim shall be deemed denied. Such decision must be written in a manner calculated to be understood by the Claimant, and it must contain:

(a) the specific reasons for the decision;

(b) specific reference(s) to pertinent Plan provisions upon which the decision was based; and

(c) such other matters as the Committee deems relevant.

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15.6 Preservation of Other Remedies. After exhaustion of the claims procedures provided under this Plan, nothing shall prevent any person from pursuing any other legal or equitable remedy otherwise available, provided that no action shall be commenced or maintained more than ninety (90) days after the final decision of the Plan Administrator on review.

ARTICLE 16. TRUST

16.1 Establishment of the Trust. The Bank may establish one or more Trusts to which it may transfer such assets as it determines in its sole discretion to assist in meeting its obligations under the Plan.

16.2 Interrelationship of the Plan and the Trust. The provisions of the Plan and the Participation Agreement shall govern the rights of a Participant to receive distributions pursuant to the Plan. The provisions of the Trust shall govern the rights of the Bank, Participants and the creditors of the Bank to the assets transferred to the Trust.

16.3 Distributions from the Trust. The Bank’s obligations under the Plan may be satisfied with Trust assets distributed pursuant to the terms of the Trust, and any such distribution shall reduce the Bank’s obligations under this Agreement.

ARTICLE 17. MISCELLANEOUS

17.1 Status of the Plan. The Plan is intended to be a plan that is not qualified within the meaning of Code Section 401(a) and that “is unfunded and is maintained by an employer primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees” within the meaning of Sections 201(2), 301(a)(3), and 401(a)(1) of ERISA. The Plan shall be administered and interpreted to the extent possible in a manner consistent with that intent. All Participant accounts and all credits and other adjustments to such Participant accounts shall be bookkeeping entries only and shall be utilized solely as a device for the measurement and determination of amounts to be paid under the Plan. No Participant accounts, credits or other adjustments under the Plan shall be interpreted as an indication that any benefits under the Plan are in any way funded.

17.2 Unsecured General Creditor. Participants and their Beneficiaries, heirs, successors and assigns shall have no legal or equitable rights, interests or claims in any property or assets of the Bank. For purposes of the payment of benefits under this Plan, any and all of the Bank’s assets, shall be, and remain, the general, unpledged, unrestricted assets of the Bank. The Bank’s obligation under the Plan shall be merely that of an unfunded and unsecured promise to pay benefits in the future.

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17.3 Employer’s Liability. The Bank’s liability for the payment of benefits shall be defined only by the Plan and the Participation Agreement, as entered into between the Bank and a Participant. The Bank shall have no obligation to a Participant under the Plan except as expressly provided in the Plan and his or her Participation Agreement.

17.4 Nonassignability. Neither a Participant nor any other person shall have any right to commute, sell, assign, transfer, pledge, anticipate, mortgage or otherwise encumber, transfer, hypothecate, alienate or convey in actual receipt, the amount, if any, payable hereunder, or any part thereof, which are, and all rights to which are expressly declared to be, unassignable and non-transferable. No part of the amounts payable shall, prior to actual payment, be subject to seizure, attachment, garnishment or sequestration for the payment of any debts, judgments, alimony or separate maintenance owed by a Participant or any other person, be transferable by operation of law in the event of a Participant’s or any other person’s bankruptcy or insolvency or be transferable to a spouse as a result of a property settlement or otherwise.

17.5 Not a Contract of Employment. Under the terms and conditions of this Plan and the Participation Agreement, this Plan shall not be deemed to constitute a contract of employment between the Bank and the Participant. Nothing in this Plan or any Participation Agreement shall be deemed to give a Participant the right to be retained in the service of the Bank as an Employee or to interfere with the right of the Bank to discipline or discharge the Participant at any time.

17.6 Furnishing Information. A Participant or his or her Beneficiary will cooperate with the Committee by furnishing any and all information requested by the Committee and take such other actions as may be requested in order to facilitate the administration of the Plan and the payments of benefits hereunder, including, but not limited to, taking such physical examinations as the Committee may deem necessary.

17.7 Terms. Except when otherwise indicated by the context, any masculine or feminine terminology used herein shall also include the neuter and other gender, and the use of any term in the singular or plural shall also include the opposite number

17.8 Captions. The captions of the articles, sections or paragraphs of this Plan are for convenience only and shall not control or affect the meaning of construction of any of its provisions.

17.9 Governing Law. Subject to ERISA, the provisions of this Plan shall be construed and interpreted according to the internal laws of the State of Hawaii without regard to its conflicts of laws principles.

17.10 Notice. Any notice or filing required or permitted to be given to the Committee under this Plan shall be sufficient if in writing and hand-delivered, or sent by registered or certified mail, to the address below:

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American Savings Bank

915 Fort Street Mall

Honolulu, HI 96813

Attn: General Counsel

Such notice shall be deemed given as of the date of delivery or, if delivery is made by mail, as of the date shown on the postmark or the receipt for registration or certification.

Any notice or filing required or permitted to be given to a Participant under this Plan shall be sufficient if in writing and hand-delivered, or sent by mail, to the last known address of the Participant.

17.11 Successors. The provisions of this Plan shall bind and inure to the benefit of the Bank and its successors and the Participant and the Participant’s designated Beneficiaries.

17.12 Validity. In case any provision of this Plan shall be illegal or invalid for any reason, said illegality or invalidity shall not affect the remaining parts hereof, but this Plan shall be construed and enforced as if such illegal or invalid provision had never been inserted herein.

17.13 Incompetent. If the Committee determines in its sole discretion that a benefit under this Plan is to be paid to a minor, a person declared incompetent or to a person incapable of handling the disposition of that person’s property, the Committee may direct payment of such benefit to the guardian, legal representative or person having the care and custody of such minor, incompetent or incapable person. The Committee may require proof of minority, incompetence, incapacity or guardianship, as it may deem appropriate prior to distribution of the benefit. Any payment of a benefit shall be a payment for the account of the Participant and the Participant’s Beneficiary, as the case may be, and shall be a complete discharge of any liability under the Plan for such payment amount.

17.14 Distribution in the Event of Taxation. If, for any reason, all or any portion of a Participant’s benefit under this Plan becomes taxable to the Participant prior to distribution, a Participant may petition the Committee or the trustee of the Trust, as applicable, for a distribution of that portion of his or her benefit that has become taxable. Upon the grant of such a petition, which grant shall not be unreasonably withheld, the Bank shall distribute to the Participant as soon as administratively feasible, funds in an amount equal to the taxable portion of his benefit (which amount shall not exceed a Participant’s unpaid Vested Account Balance under the Plan). If the petition is granted, the tax liability distribution shall be made within ninety (90) days of the date when the Participant’s petition is granted. Such a distribution shall affect and reduce the benefits to be paid under this Plan.

17.15 Insurance. The Bank, on its own behalf or on behalf of the trustee of the Trust, and in its sole discretion, may apply for and procure insurance on the life of the

24

Participant, in such amounts and in such forms as the Trust may choose. The Bank or the trustee of the Trust, as the case may be, shall be the sole owner and beneficiary of any such insurance. The Participant shall have no interest whatsoever in any such policy or policies, and at the request of the Bank shall submit to medical examinations and supply such information and execute such documents as may be required by the insurance company to whom the Bank has applied for insurance.

* * *

IN WITNESS WHEREOF, the Bank has signed this restated Plan document on September 22, 2004.

AMERICAN SAVINGS BANK, F.S.B.
By	/s/ Constance H. Lau
Its	President & CEO
By	/s/ Sherri A. Aoyama
Its	Executive Vice President

25

EX-10.2

HEI Exhibit 10.2

HAWAIIAN ELECTRIC INDUSTRIES, INC.

STOCK APPRECIATION RIGHT AGREEMENT

WITH DIVIDEND EQUIVALENTS

THIS AGREEMENT, dated effective as of April 19, 2004, is made by and between Hawaiian Electric Industries, Inc., a Hawaii corporation hereinafter referred to as the “Company,” and «Name», an employee of the Company or of a Subsidiary of the Company, hereinafter referred to as the “Employee.”

WHEREAS, the Company has heretofore adopted the 1987 Stock Option and Incentive Plan of Hawaiian Electric Industries, Inc. (as amended and restated effective January 21, 2003) (hereinafter referred to as the “Plan”);

WHEREAS, the Compensation Committee of the Company’s Board of Directors (hereinafter referred to as the “Committee”), appointed to administer the Plan, has determined that it would be to the advantage and best interest of the Company and its shareholders to grant to the Employee a stock appreciation right pursuant to the Plan as an inducement to the Employee to remain in the service of the Company or its Subsidiary and as a long-term incentive for sustained high levels of performance for the Company and its Subsidiaries; and

WHEREAS, the Committee has instructed the Company to issue said stock appreciation right, as authorized under the Plan, pursuant to the terms and conditions set forth herein;

NOW, THEREFORE, in consideration of the mutual covenants herein contained and other good and valuable consideration, the receipt of which is hereby acknowledged, the parties hereto do hereby agree as follows:

ARTICLE I

DEFINITIONS

Whenever the following terms are used in this Agreement they shall have the meanings specified below unless the context clearly indicates to the contrary.

Section 1.1 - Average Fair Market Value

“Average Fair Market Value” means, as of any determination date, the average of the daily high and low sales prices of the Common Stock on the New York Stock Exchange as quoted in the Composite Transactions published in the Western Edition of The Wall Street Journal for all trading days during the calendar month preceding the determination date. If the Common Stock is not admitted to trade on the New York Stock Exchange, the Average Fair Market Value shall be determined by the Committee in such other reasonable manner as the Committee shall decide.

Section 1.2 - Board of Directors

“Board of Directors” means the Board of Directors of the Company.

Section 1.3 - Cause

“Cause” means, with respect to the discharge by the Company or a Subsidiary of the Employee, (i) refusal to perform duties assigned in accordance with the Employee’s employment agreement with the Company or the Subsidiary, if any, or assigned by any officer of the Company or the Subsidiary, or overt and willful disobedience of orders or directives issued to the Employee by the Company or the Subsidiary, and within the scope of the Employee’s duties to the Company or the Subsidiary; (ii) commission of illegal acts in connection with the performance of duties on behalf of the Company or the Subsidiary; or (iii) material violation of the policies and procedures of the Company or the Subsidiary.

Section 1.4 – Change in Control

“Change in Control” means a “change in control of the Company” within the meaning of Section 9.1(d) of the Plan, except that clauses (iii) and (iv) thereof shall be deemed to read as follows, respectively:

(iii) there is consummated a merger or consolidation of the Company or any subsidiary of the Company with any other company, other than (A) a merger or consolidation that results in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity), in combination with the ownership of any trustee or other fiduciary holding securities under an employee benefit plan of the Company or any of its affiliates, at least 75% of the combined voting power of the voting securities of the Company or

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such surviving entity outstanding immediately after such merger or consolidation, or (B) a merger or consolidation effected to implement a recapitalization of the Company (or similar transaction) in which no Person acquires more than 50% of the combined voting power of the Company’s then outstanding securities, or

(iv) the shareholders of the Company approve a plan of complete liquidation of the Company or there is consummated a sale or disposition of all or substantially all of the Company’s assets.

Section 1.5 - Code

“Code” means the Internal Revenue Code of 1986, as amended.

Section 1.6 - Committee

“Committee” means the Compensation Committee of the Board of Directors. The Committee will consist of two or more persons who are “disinterested persons” within the meaning of Rule 16b-3 promulgated under Section 16 of the Securities Exchange Act of 1934, as amended, and “outside directors” within the meaning of Section 162(m) of the Code.

Section 1.7 - Common Stock

“Common Stock” means the Common Stock of the Company.

Section 1.8 - Fair Market Value

“Fair Market Value” means, as of any determination date, the average of the daily high and low sales prices of the Common Stock on the composite tape for stocks listed on the New York Stock Exchange as quoted in the New York Stock Exchange Composite Transactions published in the Western Edition of The Wall Street Journal on the date as of which Fair Market Value is to be determined, or if there is no trading of Common Stock on such date, the average of the daily high and low sales prices of the Common Stock as quoted in such Composite Transactions on the next preceding date on which there was trading in such shares, or if the Common Stock is not admitted to trade on the New York Stock Exchange, the Fair Market Value shall be determined by the Committee in such other reasonable manner as the Committee shall decide.

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Section 1.9 - Plan

“Plan” means the Company’s 1987 Stock Option and Incentive Plan, as amended and restated effective January 21, 2003, and as may be further amended from time to time.

Section 1.10 – SAR

“SAR” means the stock appreciation right granted under this Agreement.

Section 1.11—Subsidiary

“Subsidiary” means any corporation (other than the Company) in an unbroken chain of corporations beginning with the Company if, at the time of the granting of the SAR, each of the corporations other than the last corporation in the unbroken chain owns stock possessing 50 percent or more of the total combined voting power of all classes of stock in one of the other corporations in such chain.

Section 1.12 - Termination of Employment

“Termination of Employment” means the time when the employee-employer relationship between the Employee and the Company or a Subsidiary is terminated for any reason, including but not limited to a termination by resignation, discharge, death or retirement, but excluding any termination where there is a simultaneous reemployment by the Company or a Subsidiary. The Committee, in its sole discretion, shall determine the effect of all other matters and questions relating to Termination of Employment, including but not limited to the question of whether a Termination of Employment resulted from a discharge for Cause, and all questions of whether particular leaves of absence constitute Terminations of Employment.

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ARTICLE II

GRANT OF SAR

Section 2.1 - Grant of SAR

In consideration of the Employee’s continued service to the Company or its Subsidiaries and for other good and valuable consideration, on the date hereof the Company grants to the Employee an SAR covering any part or all of an aggregate of «Shares» shares of its Common Stock, subject to the vesting provisions and upon the terms and conditions set forth in this Agreement.

Section 2.2 – Grant Price

The grant price of the shares of Common Stock covered by the SAR shall be $52.04 per share, which represents the Average Fair Market Value as of the date of grant of the SAR.

Section 2.3 - Consideration to the Company

In consideration of the granting of the SAR by the Company the Employee agrees to render faithful and efficient services to the Company or a Subsidiary, with such duties and responsibilities as the Company shall from time to time prescribe, from the date the SAR is granted to the date of Termination of Employment. Nothing in this Agreement or in the Plan shall confer upon the Employee any right to continue in the employ of the Company or any Subsidiary or shall interfere with or restrict in any way the rights of the Company and its Subsidiaries, which are hereby expressly reserved, to discharge the Employee at any time for any reason whatsoever, with or without Cause.

Section 2.4 - Adjustments to the SAR

The number of shares, grant price and other terms and conditions of the SAR are subject to adjustment by the Committee in accordance with the applicable adjustment provisions of the Plan, as in existence on the date of this Agreement. Any such adjustment by the Committee shall be final and binding upon the Employee, the Company, and all other interested persons.

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ARTICLE III

PERIOD OF EXERCISABILITY

Section 3.1 - Commencement of Exercisability

(a) The SAR shall vest and become exercisable in four (4) cumulative installments, as follows:

(i) The first installment shall consist of 25% of the shares covered by the SAR and shall vest and become exercisable on the first anniversary of the date the SAR was granted.

(ii) The second installment shall consist of 25% of the shares covered by the SAR and shall vest and become exercisable on the second anniversary of the date the SAR was granted.

(iii) The third installment shall consist of 25% of the shares covered by the SAR and shall vest and become exercisable on the third anniversary of the date the SAR was granted.

(iv) The fourth installment shall consist of 25% of the shares covered by the SAR and shall vest and become exercisable on the fourth anniversary of the date the SAR was granted.

(b) No portion of the SAR which is unexercisable under the terms of this Agreement at Termination of Employment shall thereafter become exercisable, unless the Committee, in its sole discretion, elects to accelerate the vesting of all or any portion of the unvested shares on the date of termination.

Section 3.2 - Duration of Exercisability

The installments provided for in Section 3.1 are cumulative. Each such installment which becomes exercisable pursuant to Section 3.1 shall remain exercisable until it becomes unexercisable pursuant to Section 3.3.

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Section 3.3 - Expiration of SAR

The SAR shall expire and may not be exercised to any extent by anyone after the first to occur of the following events:

(a) The expiration of 10 years from the date the SAR was granted; or

(b) The Employee’s Termination of Employment for Cause; or

(c) The expiration of one year from the date of the Employee’s Termination of Employment for any reason other than retirement, death, disability, or Cause;

(d) The expiration of three years from the date of the Employee’s Termination of Employment as a result of the Employee’s retirement, death or disability.

Section 3.4 - Acceleration of Exercisability

(a) If the Employee’s Termination of Employment occurs as a result of retirement, then upon such retirement the SAR shall become exercisable as to all shares covered thereby, notwithstanding that the SAR may not yet have become fully exercisable under Section 3.1(a).

(b) Notwithstanding the provisions of Section 3.1, in the event of a Change in Control of the Company the SAR shall become fully vested and exercisable as to all shares covered thereby.

ARTICLE IV

EXERCISE OF THE SAR

Section 4.1 - Persons Eligible to Exercise

During the lifetime of the Employee, only the Employee may exercise the SAR, or any portion thereof. After the death of the Employee any exercisable portion of the SAR may, prior to the time when the SAR becomes unexercisable pursuant to Section 3.3, be exercised by the Employee’s personal representative or by any person empowered to do so under the Employee’s will or under the then applicable laws of descent and distribution.

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Section 4.2 - Partial Exercise

Any exercisable portion of the SAR or the entire SAR, if then wholly exercisable, may be exercised in whole or in part at any time prior to the time when the SAR or portion thereof becomes unexercisable pursuant to Section 3.3; provided, however, that each partial exercise shall be in respect of not less than one thousand (1,000) shares covered by the SAR (or minimum installment set forth in Section 3.1, if a smaller number of shares) and shall be for whole shares only.

Section 4.3 - Manner of Exercise

The SAR, or any exercisable portion thereof, may be exercised solely by delivery to the Company of all of the following prior to the time when the SAR or such portion becomes unexercisable pursuant to Section 3.3:

(a) Notice in writing signed by the Employee or other person then entitled to exercise the SAR or portion, stating that the SAR or portion is thereby exercised, such notice complying with all applicable rules established by the Committee; and

(b) In the event the SAR or portion shall be exercised by any person or persons other than the Employee, appropriate proof of the right of such person or persons to exercise the SAR.

Section 4.4 - - Payment Upon Exercise

Upon exercise of the SAR (or portion thereof), subject to Section 6.5, the Company shall deliver to the Employee a number of shares of Common Stock with a Fair Market Value on the date of exercise equal to the product of (i) the number of shares of Common Stock covered by the SAR (or portion thereof being exercised) and (ii) the excess of the Fair Market Value of a share of Common Stock on the date of exercise over the grant price determined in accordance with Section 2.2.

Section 4.5 - Conditions to Issuance of Stock Certificates

The shares of Common Stock deliverable upon the exercise of the SAR, or any part thereof, may be either previously authorized but unissued shares or issued shares which have been reacquired by the Company. Such shares shall be fully paid and nonassessable. Unless waived by the Committee, in its sole discretion, the Company shall not be required to issue or deliver any certificate or certificates for shares of

- 8 -

Common Stock upon exercise of the SAR or part thereof prior to fulfillment of all of the following conditions:

(a) The admission of such shares to listing on all stock exchanges on which such class of stock is then listed; and

(b) The completion of any registration or other qualification of such shares, or the completion of any arrangements necessary or advisable to qualify for an exemption from any such registration or other requirements, under any state or federal law or under rulings or regulations of the Securities and Exchange Commission or of any other governmental regulatory body, which the Committee shall, in its sole discretion, deem necessary or advisable, including the completion of any reasonable action that the Committee may request the Employee to take in order to satisfy all such regulatory requirements; and

(c) The obtaining of any approval or other clearance from any state or federal governmental agency which the Committee shall, in its sole discretion, determine to be necessary or advisable; and

(d) The lapse of such reasonable period of time following the exercise of the SAR as the Committee may from time to time establish for reasons of administrative convenience; and

(e) The conclusion of any arrangements that may be required to satisfy the Company’s obligation to withhold taxes.

Section 4.6 - Rights as Shareholders

The holder of the SAR shall not be, nor have any of the rights or privileges of, a shareholder of the Company in respect of any shares issuable upon exercise of any part of the SAR unless and until certificates representing such shares shall have been issued by the Company to such holder.

Section 4.7 - Company Obligations

In the event the Company fails to fulfill its obligations under this Agreement, the Company shall be liable to the Employee, his beneficiary or any other person entitled to exercise the SAR under this Agreement, for any attorney’s fees and other legal costs related to enforcing such person’s rights under this Agreement.

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ARTICLE V

DIVIDEND EQUIVALENTS

The Employee also shall be awarded, at no additional cost, “Dividend Equivalents” based on the dividends declared on record dates during (and only during) the vesting period specified in Section 3.1 hereof, or during any shorter vesting period pursuant to Section 3.4 hereof. Dividend equivalents shall be paid in the form of Common Stock and shall be paid only in the event and to the extent that the Employee exercises the SAR. The number of Dividend Equivalent shares to be paid to the Employee upon exercise of the SAR shall be computed as follows:

(a) As of each dividend record date during the vesting period, the dividend which would be payable with respect to the sum of (i) the number of shares with respect to which the SAR is then unexercised, and (ii) the number of Dividend Equivalent shares calculated for all previous periods but not issued prior to the dividend record date shall be computed. The number of Dividend Equivalent shares to be accrued as of the dividend record date shall then be determined by dividing the dividend which would be payable as of such record date on the number of shares determined by adding items (i) and (ii) of the preceding sentence by the Fair Market Value of the Common Stock as of such record date.

(b) The total number of Dividend Equivalent shares potentially available to the Employee upon any exercise of the SAR shall be equal to the difference between (i) the total number of Dividend Equivalent shares earned by the Employee for all dividend record dates prior to the date of such exercise (as determined pursuant to paragraph (a) above and (ii) the total number of Dividend Equivalent shares previously paid to the Employee in connection with any prior exercise(s) of the SAR.

(c) The number of Dividend Equivalent shares to be paid to the Employee upon any exercise of the SAR shall be equal to the total number of Dividend Equivalent shares potentially available to the Employee upon such exercise (as determined pursuant to paragraph (b) above) multiplied by a fraction, the numerator of which is the number of shares with respect to which the SAR is then being exercised and the denominator of which is the number of shares with respect to which the SAR was unexercised immediately prior to said exercise.

(d) Dividend Equivalents shall be paid only in the form of whole shares of Common Stock. No fractional shares shall be issued upon payment of Dividend Equivalents, but a cash payment shall be made by the Company in lieu of fractional shares.

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ARTICLE VI

MISCELLANEOUS

Section 6.1 - Administration

The Committee shall have the power to interpret the Plan and this Agreement and to adopt such rules for the administration, interpretation and application of the Plan as are consistent therewith and to interpret or revoke any such rules. All actions taken and all interpretations and determinations made by the Committee in good faith shall be final and binding upon the Employee, the Company and all other interested persons. No member of the Committee shall be personally liable for any action, determination, or interpretation made in good faith with respect to the Plan or the SAR.

Section 6.2 – SAR Not Transferable

Neither the SAR nor any interest or right therein or part thereof shall be liable for the debts, contracts, or engagements of the Employee or his successors in interest or shall be subject to disposition by transfer, alienation, anticipation, pledge, encumbrance, assignment or any other means whether such disposition be voluntary or involuntary or by operation of law by judgment, levy, attachment, garnishment or any other legal or equitable proceedings (including bankruptcy) and any attempted disposition thereof shall be null and void and of no effect; provided, however, that this Section 6.2 shall not prevent transfers by will or by the applicable laws of descent and distribution.

Section 6.3 - Shares to be Reserved

The Company shall at all times during the term of the SAR reserve and keep available such number of shares of Common Stock as will be sufficient to satisfy the requirements of this Agreement.

Section 6.4 - Fractional Shares

Notwithstanding any other provision of this Agreement to the contrary, no fractional shares shall be issued upon exercise of the SAR, but cash payment shall be made by the Company in lieu of fractional shares.

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Section 6.5 - Withholding of Taxes

The Company may make such provisions as it deems appropriate to withhold any taxes the Company or any Subsidiary is required to withhold (including any amounts required to be withheld in order for the Company or any Subsidiary to obtain a tax deduction), or to require the Employee to take any action necessary to satisfy any withholding obligations of the Company, in connection with the grant or exercise of the SAR, or in connection with the sale or other disposition of shares acquired upon exercise of the SAR, and the Employee agrees to be bound by the same (including any provision whereby the Company withholds from the shares of Common Stock otherwise issuable to the Employee as a result of the exercise of the SAR a number of shares having a Fair Market Value equal to the minimum tax withholding obligation). With the consent of the Company, the Employee may satisfy any such withholding tax obligation by: (a) tendering a cash payment; (b) authorizing the Company to withhold from the shares of Common Stock otherwise issuable to the Employee as a result of the exercise of the SAR a number of shares having a Fair Market Value, as of the date the withholding tax obligation arises, less than or equal to the amount of the withholding tax obligation; or (c) delivering to the Company already owned and unencumbered and unrestricted shares of Common Stock having a Fair Market Value, as of the date the withholding tax obligation arises, less than or equal to the amount of the withholding tax obligation.

Section 6.6 - Notices

Any notice to be given under the terms of this Agreement to the Company shall be addressed to the Company in care of its Secretary and any notice to be given to the Employee shall be addressed to the Employee at the address given beneath the Employee’s signature hereto. By a notice given pursuant to this Section 6.6, either party may hereafter designate a different address for notices to be given to such party. Any notice which is required to be given to the Employee shall, if the Employee is then deceased, be given to the Employee’s personal representative if such representative has previously informed the Company of his status and address by written notice under this Section 6.6. Any notice shall be deemed duly given when enclosed in a properly sealed envelope or wrapper addressed as aforesaid, deposited (with postage prepaid) in a post office or branch post office regularly maintained by the United States Postal Service.

Section 6.7 - Entire Agreement; Relationship to the Plan

This Agreement and the Plan sets forth the sole entire agreement and understanding between the parties as to the subject matter hereof, and merges with and supersedes all prior and contemporaneous discussions, agreements and understandings of every and any nature between them with respect to the subject matter hereof. Except to

- 12 -

the extent provided in Section 6.1, and except to the extent that provisions hereof are by their terms subject to any subsequent amendment of the Plan, this Agreement may not be changed or modified, except by agreement in writing, signed by the party to be bound thereby. In the event of any conflict or inconsistency between this Agreement and the Plan as written on the date of this Agreement, the Plan shall govern.

Section 6.8 - Parties in Interest

All the terms and provisions of this Agreement shall be binding upon and inure to the benefit of and be enforceable by the parties hereto and their respective successors in interest.

Section 6.9 - Severability

The provisions of this Agreement are severable, and if any one or more provisions shall be determined to be judicially unenforceable, in whole or in part, the remaining provisions, and any partially unenforceable provisions, to the extent enforceable, shall nevertheless be binding and enforceable upon the parties hereto.

Section 6.10 - Headings

The headings in the Sections of this Agreement are provided for convenience only and shall not serve as a basis for interpretation or construction of this Agreement.

Section 6.11 - Counterparts

This Agreement may be executed simultaneously in two (2) or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same instrument.

Section 6.12 - Governing Law

This Agreement and the rights of the parties hereunder shall be interpreted in accordance with, and governed by, the laws of the State of Hawaii.

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IN WITNESS WHEREOF, this Agreement has been executed and delivered by the parties hereto effective as of the day and year first above written.

	HAWAIIAN ELECTRIC INDUSTRIES, INC.
	By
		Chairman, HEI Compensation Committee
	By
		Vice President – Administration & Corporate Secretary
«Name»

Employee’s Social Security Number: «SSN»

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EX-12.1

HEI Exhibit 12.1 (page 1 of 3)

Hawaiian Electric Industries, Inc. and Subsidiaries

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

(unaudited)

Nine months ended September 30	2004(1)			2004(2)			2003(1)			2003(2)
(dollars in thousands)
Fixed charges
Total interest charges (3)	$	112,523		$	147,857		$	106,300		$	147,482
Interest component of rentals		2,889			2,889			3,225			3,225
Pretax preferred stock dividend requirements of subsidiaries		2,244			2,244			2,345			2,345
Preferred securities distributions of trust subsidiaries		—			—			12,026			12,026
Total fixed charges	$	117,656		$	152,990		$	123,896		$	165,078
Earnings
Pretax income	$	163,407		$	163,407		$	126,532		$	126,532
Fixed charges, as shown		117,656			152,990			123,896			165,078
Interest capitalized		(2,236	)		(2,236	)		(1,385	)		(1,385	)
Earnings available for fixed charges	$	278,827		$	314,161		$	249,043		$	290,225
Ratio of earnings to fixed charges		2.37			2.05			2.01			1.76

⁽¹⁾ Excluding interest on ASB deposits.

⁽²⁾ Including interest on ASB deposits.

⁽³⁾ Interest on nonrecourse debt from leveraged leases is not included in total interest charges nor in interest expense in HEI’s consolidated statements of income.

HEI Exhibit 12.1 (page 2 of 3)

Hawaiian Electric Industries, Inc. and Subsidiaries

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

(unaudited)

(continued)

Years ended December 31	2003(1)			2003(2)			2002(1)			2002(2)			2001(1)			2001(2)
(dollars in thousands)
Fixed charges
Total interest charges (3)	$	138,808		$	192,616		$	151,543		$	225,174		$	175,780		$	292,311
Interest component of rentals		4,214			4,214			4,501			4,501			4,268			4,268
Pretax preferred stock dividend requirements of subsidiaries		3,082			3,082			3,069			3,069			3,069			3,069
Preferred securities distributions of trust subsidiaries		16,035			16,035			16,035			16,035			16,035			16,035
Total fixed charges	$	162,139		$	215,947		$	175,148		$	248,779		$	199,152		$	315,683
Earnings
Pretax income from continuing operations	$	182,415		$	182,415		$	181,909		$	181,909		$	165,903		$	165,903
Fixed charges, as shown		162,139			215,947			175,148			248,779			199,152			315,683
Interest capitalized		(1,914	)		(1,914	)		(1,855	)		(1,855	)		(2,258	)		(2,258	)
Earnings available for fixed charges	$	342,640		$	396,448		$	355,202		$	428,833		$	362,797		$	479,328
Ratio of earnings to fixed charges		2.11			1.84			2.03			1.72			1.82			1.52

⁽¹⁾ Excluding interest on ASB deposits.

⁽²⁾ Including interest on ASB deposits.

⁽³⁾ Interest on nonrecourse debt from leveraged leases is not included in total interest charges nor in interest expense in HEI’s consolidated statements of income.

HEI Exhibit 12.1 (page 3 of 3)

Hawaiian Electric Industries, Inc. and Subsidiaries

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

(unaudited)

(continued)

Years ended December 31	2000(1)			2000(2)			1999(1)			1999(2)
(dollars in thousands)
Fixed charges
Total interest charges (3)	$	196,980		$	316,172		$	158,947		$	279,285
Interest component of rentals		4,332			4,332			4,370			4,370
Pretax preferred stock dividend requirements of subsidiaries		3,109			3,109			3,407			3,407
Preferred securities distributions of trust subsidiaries		16,035			16,035			16,025			16,025
Total fixed charges	$	220,456		$	339,648		$	182,749		$	303,087
Earnings
Pretax income from continuing operations	$	170,495		$	170,495		$	155,129		$	155,129
Fixed charges, as shown		220,456			339,648			182,749			303,087
Interest capitalized		(2,922	)		(2,922	)		(2,576	)		(2,576	)
Earnings available for fixed charges	$	388,029		$	507,221		$	335,302		$	455,640
Ratio of earnings to fixed charges		1.76			1.49			1.83			1.50

⁽¹⁾ Excluding interest on ASB deposits.

⁽²⁾ Including interest on ASB deposits.

⁽³⁾ Interest on nonrecourse debt from leveraged leases is not included in total interest charges nor in interest expense in HEI’s consolidated statements of income.

EX-31.1

HEI Exhibit 31.1

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

I, Robert F. Clarke, certify that:

1. I have reviewed this report on Form 10-Q for the quarter ended September 30, 2004 of Hawaiian Electric Industries, Inc. (“registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 5, 2004

/s/    ROBERT F. CLARKE        

Robert F. Clarke

Chairman, President and Chief Executive Officer

EX-31.2

HEI Exhibit 31.2

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

I, Eric K. Yeaman, certify that:

1. I have reviewed this report on Form 10-Q for the quarter ended September 30, 2004 of Hawaiian Electric Industries, Inc. (“registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 5, 2004

/s/    ERIC K. YEAMAN        

Eric K. Yeaman

Financial Vice President, Treasurer and

Chief Financial Officer

EX-32.1

HEI Exhibit 32.1

Hawaiian Electric Industries, Inc.

Written Statement of Chief Executive Officer Furnished Pursuant to

18 U.S.C. Section 1350,

as Adopted by

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of Hawaiian Electric Industries, Inc. (HEI) on Form 10-Q for the quarter ended September 30, 2004 as filed with the Securities and Exchange Commission (the Report), I, Robert F. Clarke, Chief Executive Officer of HEI, certify, pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1) The Report fully complies with the requirements of section 13(a) of the Securities Exchange Act of 1934; and

(2) The consolidated information contained in the Report fairly presents, in all material respects, the financial condition as of September 30, 2004 and results of operations for the three and nine months ended September 30, 2004 of HEI and its subsidiaries.

/s/    ROBERT F. CLARKE        

Robert F. Clarke

Chairman, President and Chief Executive Officer of HEI

Date: November 5, 2004

A signed original of this written statement required by Section 906 has been provided to Hawaiian Electric Industries, Inc. and will be retained by Hawaiian Electric Industries, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

HEI Exhibit 32.2

Hawaiian Electric Industries, Inc.

Written Statement of Chief Financial Officer Furnished Pursuant to

18 U.S.C. Section 1350,

as Adopted by

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of Hawaiian Electric Industries, Inc. (HEI) on Form 10-Q for the quarter ended September 30, 2004 as filed with the Securities and Exchange Commission (the Report), I, Eric K. Yeaman, Chief Financial Officer of HEI, certify, pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1) The Report fully complies with the requirements of section 13(a) of the Securities Exchange Act of 1934; and

(2) The consolidated information contained in the Report fairly presents, in all material respects, the financial condition as of September 30, 2004 and results of operations for the three and nine months ended September 30, 2004 of HEI and its subsidiaries.

/s/    ERIC K. YEAMAN        

Eric K. Yeaman

Financial Vice President, Treasurer and

Chief Financial Officer of HEI

Date: November 5, 2004

A signed original of this written statement required by Section 906 has been provided to Hawaiian Electric Industries, Inc. and will be retained by Hawaiian Electric Industries, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-10.3

HECO Exhibit 10.3

CONFIRMATION AGREEMENT

CONCERNING SECTION 5.2B(2) OF POWER PURCHASE AGREEMENT AND

AMENDMENT NO. 5 TO POWER PURCHASE AGREEMENT

This Confirmation Agreement Concerning Section 5.2B(2) of Power Purchase Agreement and Amendment No. 5 to Power Purchase Agreement (“Increment One Capacity Agreement”) is made and entered into as of the date of the last execution hereof, as set forth below the respective signature blocks of the parties, by and between HAWAIIAN ELECTRIC COMPANY, INC., a Hawaii corporation (“HECO”), and KALAELOA PARTNERS, L.P., a Delaware limited partnership (“Kalaeloa”).

Recitals:

A. HECO and Kalaeloa entered into a Power Purchase Agreement, dated as of October 14, 1988, as amended and clarified by (i) Amendment No. 1 to Power Purchase Agreement dated as of June 15, 1989, (ii) Restated and Amended Amendment No. 2 to Power Purchase Agreement dated as of February 9, 1990, (iii) Amendment No. 3 to Power Purchase Agreement dated as of December 10, 1991, (iv) Agreement to Clarify and Interpret dated as of March 31, 1997, and (v) Amendment No. 4 to Power Purchase Agreement dated as of October 1, 1999 (as so amended and clarified, the “Power Purchase Agreement”), which provides for, among other things, the sale by Kalaeloa and the purchase by HECO of electric energy and capacity from Kalaeloa’s combined cycle oil-fired cogeneration facility located at Barbers Point, Oahu, Hawaii.

B. HECO and Kalaeloa have executed certain letter agreements clarifying the interpretation and/or application of certain provisions of the Power Purchase Agreement.

C. Section 5.2B(2) of the Power Purchase Agreement reads as follows:

In the event that a performance test consistent with Good Engineering and Operating Practices and reasonably satisfactory to both parties conducted immediately prior to any “C” inspection after the In-Service Date of the Facility demonstrates that the Facility is able to continuously deliver more than 180,000 KW of Firm Capacity, Section 1.22, Section 3.3C(1) of this Agreement, and Attachment D to this Agreement may at Kalaeloa’s option be revised to reflect the capacity established by such test as the maximum capacity the Facility is capable of delivering under HECO dispatch (but not more than 189,000 KW). The maximum capacity thus established shall thereupon become the Firm Capacity under this Agreement. The Capacity Charge rate applicable to the Firm Capacity in excess of 180,000 KW shall be $112 per KW per year (“Excess Capacity Charge Rate”).

D. HECO and Kalaeloa have disagreed over the timing and protocol of the performance test referred to in said Section 5.2B(2).

E. Kalaeloa has made or will make certain capital investments at the Facility to allow the Facility to meet its intended design capability, which investments include modifications to the exhaust gas diffuser, added heat exchange surface, boiler wash capability (including associated water treatment system) and combustion turbine evaporative cooling (collectively, the “Investments to Meet Intended Design Capability”).

F. Notwithstanding the parties’ disagreement regarding the timing and protocol of the performance test referred to in said Section 5.2B(2), Kalaeloa has been making available to HECO energy in excess of 180,000 KWH per hour and HECO has from time to time dispatched such additional energy pursuant to Sections 3.1B and 3.2D(4) of the Power Purchase Agreement.

G. HECO has decided that it is beneficial to itself and its customers, and Kalaeloa has decided that it is beneficial to itself and its owners, for Kalaeloa to provide and HECO to accept an increase in Firm Capacity of nine (9) megawatts pursuant to said Section 5.2B(2) of the Power Purchase Agreement and this Increment One Capacity Agreement, subject to approval of this Increment One Capacity Agreement by the Public Utilities Commission.

H. In light of the facts set forth in Recitals F and G above, HECO and Kalaeloa have collected certain data as set forth in the letter dated April 21, 2004 attached hereto as Exhibit 1 and have agreed on the protocol for the performance evaluation regarding the increase in Firm Capacity as set forth in the Capacity Evaluation Protocol Kalaeloa Cogeneration Facility Case for up to 189 MW, a copy of which is attached hereto as Exhibit 2.

I. The data collected pursuant to tests conducted on April 21, 2004 through April 23, 2004 under such protocol having demonstrated that the Facility is able to deliver the capacity of 189,000 KW under HECO Dispatch, HECO and Kalaeloa desire to settle all disputed issues arising out of said Section 5.2B(2) of the Power Purchase Agreement, to confirm the increase in Firm Capacity provided for in said Section 5.2B(2), to establish an in-service date for such increased capacity contingent upon certain approvals from the Public Utilities Commission, and to otherwise amend certain provisions of the Power Purchase Agreement in light of certain recent changes in circumstance.

J. An additional complication for administration of the Power Purchase Agreement has arisen out of the action of the U.S. Bureau of Labor Statistics to cease publication of the Producer Price Index for magnesium ingots, which had been used by the parties to calculate the “Additive Component” of the Energy Charge under the Power Purchase Agreement, and the failure to date of HECO and Kalaeloa to agree upon an alternate method of calculating the “Additive Component.”

NOW, THEREFORE, in consideration of the premises and mutual agreements and covenants contained in this Increment One Capacity Agreement and for other good and valuable consideration (including, but not limited to, the avoidance of the expense and uncertainty of formal dispute resolution under the Power Purchase Agreement), the receipt and adequacy of which are hereby acknowledged, the parties hereby settle, with effect as set forth herein, their disputes over Section 5.2B(2) of the Power Purchase Agreement and the method of

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calculating the Additive Component of the Energy Charge, confirm the increase in Firm Capacity provided for in said Section 5.2B(2), and otherwise agree as follows:

1. Definitions.

Regardless of whether or not the Increment One Capacity In-Service Date has occurred, (i) capitalized terms used in Sections 3 and 9 through 14 of this Increment One Capacity Agreement and defined in Section 2 of this Increment One Capacity Agreement have the respective meaning given them in Section 2 and (ii) capitalized terms used but not defined in this Increment One Capacity Agreement have the respective meaning given to them in the Power Purchase Agreement.

2. Regarding Article I of the Power Purchase Agreement.

Effective upon the occurrence of the Increment One Capacity In-Service Date, Article I of the Power Purchase Agreement is deemed amended by modifying Sections 1.6 and 1.22 to read in their entirety as set forth below, and by adding the definitions set forth below as Sections 1.58 through 1.95:

1.6 Capacity Charge – The amount to be paid by HECO to Kalaeloa pursuant to Section 5.2 of this Agreement based on Baseline Capacity plus the New Capacity available to the HECO system from the Facility.

1.22 Firm Capacity – The sum of the following: Baseline Capacity plus the Increment One Capacity.

* * *

1.58 Additive Component Credit – The difference between the amount, as determined on the basis of the Pre-Transition Date Formula, of the Additive Component of the Energy Charge incurred by HECO for Calendar Year 2003 and the amount actually paid by HECO as the Additive Component of the Energy Charge incurred for Calendar Year 2003, as set forth in Section 3.B. of the Increment One Capacity Agreement.

1.59 Additive Component Offset – The difference between (i) the amount of the Additive Component of the Energy Charge that would have been incurred by HECO for the Pre-Transition Date Period had the Post-Transition Date Formula been in effect for such Period and (ii) the amount actually paid by HECO, as determined on the basis of the Pre-Transition Date Formula, as the Additive Component of the Energy Charge incurred for the Pre-Transition Date Period. The Additive Component Offset is to be set off against the Additive Component Credit for purposes of determining the Transition Date, as set forth in Section 3.C.4 of the Increment One Capacity Agreement.

1.60 Annual New Capacity Charge – For each Contract Year, the Capacity Charge incurred by HECO for the New Capacity during such Contract Year pursuant to Section 5.2A(1).

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1.61 August 2003 PPI Final Value – 98.6, which is the last monthly final value for the Producer Price Index for magnesium ingots published by the U.S. Bureau of Labor Statistics.

1.62 Base Additive GNPIPD – The value of GNPIPD on January 1, 2004 as determined by the Final value of GNPIPD for the fourth quarter of 2003 published by the U.S. Bureau of Economic Analysis and which shall be the denominator in the fraction to be used in the Post-Transition Date Formula. For purposes of calculating the Additive Component Offset for Calendar Year 2004 pursuant to Section 3.C.4 of the Increment One Capacity Agreement, the Base Additive GNPIPD value shall be 106.243.

1.63 Baseline Capacity – 180,000 KW at 0.85 power factor.

1.64 Calendar Year – The period from and including January 1 through and including the next following December 31.

1.65 Capacity For Which Capacity Charges Are Being Incurred – The total capacity for which a Capacity Charge is payable under Section 5.2A(1) without giving effect to any reductions in or deductions from the Capacity Charge pursuant to any other provisions of this Agreement.

1.66 Consumer Advocate is defined in Section 23.20.

1.67 Current Additive GNPIPD – For Calendar Year 2004 and for each Calendar Year thereafter, the value of GNPIPD on January 1 of the Calendar Year in question as determined by the Final value of GNPIPD for the fourth quarter of the previous Calendar Year published by the U.S. Bureau of Economic Analysis, which shall be the numerator in the fraction to be used in the Post-Transition Date Formula for the Calendar Year in question. For purposes of calculating the Additive Component Offset for Calendar Year 2004 pursuant to Section 3.C.4 of the Increment One Capacity Agreement, the Current Additive GNPIPD shall be 106.243.

1.68 December 2002 PPI Final Value – 134.3, which is the monthly final value for the Producer Price Index for magnesium ingots published by the U.S. Bureau of Labor Statistics.

1.69 Delay Degradation – Any degradation in Facility performance occurring under the conditions set forth in Section 3.2D(9) (captioned “Degradation Exemption”) of the Power Purchase Agreement, for the period Kalaeloa is entitled to such “Degradation Exemption.”

1.70 Demonstrated Facility Capacity – The maximum capacity of 189,000 KW, as demonstrated by the data collected and corrected pursuant to the tests conducted on April 21, 2004 through April 23, 2004 under the protocol attached as Exhibit 2 to the Increment One Capacity Agreement.

1.71 FIN No. 46R is defined in Section 23.20.

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1.72 Final – The value first published by the U.S. Bureau of Economic Analysis as “final” (as opposed to “advance” or “preliminary”) for GNPIPD for the quarter in question, such “final” value usually being published the third month after the close of such quarter. Subsequent revisions (sometimes referred to as “revised estimates”) by the U.S. Bureau of Economics Analysis to the value first published as “final” shall not constitute the “Final” value for purposes of making adjustments tied to changes in GNPIPD under this Agreement except to the extent that the provisions of Section 3.C.5 and/or paragraph c of Section 8.I of the Increment One Capacity Agreement, by requiring that GNPIPD values used to make adjustments tied to GNPIPD be selected from the same U.S. Bureau of Economic Analysis publication, permit the value of the Base Additive GNPIPD and/or the value of the 1987 Final GNPIPD, respectively, to be updated.

1.73 Incentive Energy – For each Contract Year from and after the Increment One Capacity In-Service Date, the Net Electrical Energy Output accepted by HECO in excess of HECO’s minimum energy purchase obligation for such Contract Year as set forth in Section 5.1D.

1.74 Increment One Capacity – The first 9,000 KW at 0.85 power factor of Demonstrated Facility Capacity beyond the Baseline Capacity.

1.75 Increment One Capacity Agreement – The Confirmation Agreement Concerning Section 5.2B(2) of the Power Purchase Agreement and Amendment No. 5 to Power Purchase Agreement by and between HECO and Kalaeloa.

1.76 Increment One Capacity In-Service Date – The Increment One Rate Inclusion Date, provided that the conditions precedent to the effectiveness of Sections 2 and 4 through 9 of the Increment One Capacity Agreement as set forth in Section 13 of the Increment One Capacity Agreement have been satisfied.

1.77 Increment One Rate Inclusion Date – The effective date of an interim or final order (whichever is first) of the Public Utilities Commission in a HECO general rate case using a 2005 calendar year test year that includes in HECO’s base electric rates the additional purchased power costs (including the Capacity Charge for the Increment One Capacity and the Variable O&M Component of the Energy Charge) incurred by HECO pursuant to the Increment One Capacity Agreement.

1.78 Information is defined in Section 23.20.

1.79 January 2003 Final PPI Value – 101.3, which is the monthly final value for the Producer Price Index for magnesium ingots published by the U.S. Bureau of Labor Statistics.

1.80 Minimum Thermal Threshold – For any Calendar Year, shall be an Operating Thermal Threshold of twelve percent (12%), provided, however, that in the event that HECO determines, in its sole discretion, that the Power Purchase Agreement is likely to be deemed to be an arrangement containing a lease within the scope of Financial Accounting Standards Board (“FASB”) Statement No. 13, Accounting for Leases, by

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reason of the Minimum Thermal Threshold being 12%, then the Minimum Thermal Threshold shall upon written notice by HECO to Kalaeloa be increased to an Operating Thermal Threshold of fifteen percent (15%) for the next Calendar Year and subsequent years.

1.81 New Capacity – The Increment One Capacity.

1.82 Ninety is defined in Section 25.2.

1.83 On-peak Monthly Steam Average is defined in Section 23.18.

1.84 On-peak Period – The fourteen (14) hour period from and including 7:00 a.m. through and including 8:59 p.m. each day.

1.85 One Hundred Eighty-Nine is defined in Section 25.1.

1.86 Operating Thermal Threshold – The ratio, for the Calendar Year in question, of the Facility’s useful thermal output for such Calendar Year divided by the sum of (i) the useful electrical output for such Calendar Year plus (ii) the useful thermal output for such Calendar Year. This ratio is to be expressed as a percentage.

1.87 Post-Transition Date Formula – The formula used to adjust the value of the Additive Component to be used in the calculation of the Energy Charge incurred on or after the Transition Date as further described in Section 5.1A.

1.88 Post-Transition Date Period – The period from and after the Transition Date until the end of the Term.

1.89 PPI Dispute – The dispute between Kalaeloa and HECO over the calculation of the “Additive Component” of the Energy Charge in light of the action of the U.S. Bureau of Labor Statistics to cease publication of the Producer Price Index for magnesium ingots.

1.90 Pre-Transition Date Formula – The formula used to adjust the value of the Additive Component to be used in the calculation of the Energy Charge incurred for Calendar Year 2003 and for the Pre-Transition Date Period as further described in Section 5.1A.

1.91 Pre-Transition Date Period – The period from and including January 1, 2004 through the day prior to the Transition Date.

1.92 Recipient is defined in Section 23.20.

1.93 SOX 404 is defined in Section 23.20.

1.94 Transition Date – The first day of the calendar month following the calendar month for which the balance of the Additive Component Credit is reduced to zero or less by subtraction therefrom of the Additive Component Offset, as set forth in

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Section 3.C.4 of the Increment One Capacity Agreement.

1.95 Variable O&M Component is defined in Section 5.1E.

3. Additive Component.

A. Regarding Calculation of “Additive Component” Under Section 5.1 of the Power Purchase Agreement.

The definition of the “Additive Component” set forth towards the end of Section 5.1A of the Power Purchase Agreement shall apply only to the Additive Component of the Energy Charge incurred prior to January 1, 2003. With respect to subsequent periods, the aforesaid definition of the “Additive Component” is supplemented as follows:

The “Additive Component” of the Energy Charge incurred for Calendar Year 2003 and for the Pre-Transition Date Period shall be:

0.144 cents/KWH multiplied by 0.88704028 (which product accounts for the change in the Producer Price Index for magnesium ingots from 114.2 in January of 1988 to 101.3 in January of 2003).

The “Additive Component” of the Energy Charge incurred on or after the Transition Date shall be:

0.144 cents/KWH multiplied by 1.019702277 (which product is being used as a proxy for the change in the Producer Price Index for magnesium ingots from 114.2 in January of 1988 to the month during which the Transition Date occurs, for which 116.45 shall be used as the value for such month because it represents the midpoint of the August 2003 PPI Final Value and the December 2002 PPI Final Value, which midpoint is the compromise value for the month during which the Transition Date occurs agreed to by Kalaeloa and HECO) multiplied by the quotient of the Current Additive GNPIPD divided by the Base Additive GNPIPD.

B. Regarding Credit for Payment of Additive Component of the Energy Charge Incurred for Calendar Year 2003.

HECO paid Kalaeloa for the “Additive Component” of the Energy Charge incurred for Calendar Year 2003 on the basis of 0.144 cents/KWH multiplied by 1.17600701, which is the quotient of 114.2 (which represents the January 1988 final value of the Producer Price Index for magnesium ingots) and 134.3 (which represents the preliminary value published by the U.S. Bureau of Labor Statistics for the Producer Price Index for magnesium ingots for the month of January 2003). Recalculating the “Additive Component” incurred for Calendar Year 2003 on the basis of the Pre-Transition Date Formula (which uses the January 2003 Final PPI Value in lieu of the aforesaid preliminary value) results in a difference of $555,530.42 to HECO’s credit. As part of the settlement of the PPI Dispute, this amount (without interest) will

7

be credited to HECO pursuant to the mechanism set forth in Section 3.C.4 of this Increment One Capacity Agreement.

C. Regarding Payment of “Additive Component.”

1. Periods Prior to January 1, 2003. Kalaeloa and HECO agree that the calculation of the “Additive Component” of the Energy Charge incurred for all periods prior to January 1, 2003 was properly done if performed pursuant to the only formula provided for in the Power Purchase Agreement prior to the execution of the Increment One Capacity Agreement, and that any claim for adjustment to the Additive Component incurred for any such period(s) shall be resolved solely in accordance with Section 6.3 of the Power Purchase Agreement. Both Kalaeloa and HECO hereby waive all claims (other than claims under said Section 6.3) each may have against the other arising out of the calculation and payment of the “Additive Component” for the Energy Charge incurred for all periods prior to January 1, 2003.

2. Calendar Year 2003 and the Pre-Transition Date Period. For the Energy Charge incurred for Calendar Year 2003 and for the Pre-Transition Date Period, HECO shall pay, pursuant to Section 6.2 of the Power Purchase Agreement, the Additive Component of the Energy Charge on the basis of the Pre-Transition Date Formula.

3. Post-Transition Date Period. For the Energy Charge incurred on or after the Transition Date, HECO shall pay, pursuant to Section 6.2 of the Power Purchase Agreement, the Additive Component of the Energy Charge on the basis of the Post-Transition Date Formula.

4. Additive Component Credit and Additive Component Offset. The Additive Component Credit and the Additive Component Offset will be used to determine the Transition Date as provided in this Section 3.C.4. For each month of the Pre-Transition Date Period, a calculation will be made of the Additive Component of the Energy Charge that would have been incurred by HECO for such month had the Post-Transition Date Formula been in effect for such month. The difference between this amount and the amount actually paid by HECO pursuant to Section 3.C.2 above as the Additive Component of the Energy Charge incurred for such month shall constitute the Additive Component Offset for such month. Each monthly Additive Component Offset shall be subtracted from the then remaining balance of the Additive Component Credit until the balance of the Additive Component Credit is zero or less. The first day of the calendar month following the month for which the balance of the Additive Component Credit is reduced to zero or less shall be the Transition Date. Any portion of the Additive Component Offset for the last month of the Pre-Transition Date Period which remains unused once the balance of the Additive Component Credit is reduced to zero or less as aforesaid shall be extinguished and HECO shall make no payment to Kalaeloa on account of such unused portion.

5. Miscellaneous. Although the provisions of Section 8.I of this Increment One Capacity Agreement do not strictly apply to the Base Additive GNPIPD and the Current Additive GNPIPD used in the Post-Transition Date Formula due to such Formula’s use of the Final value of GNPIPD for the fourth quarter of 2003 rather than the Final value for the fourth quarter of 1987 used in the GNPIPD adjustment factor referenced in the aforesaid Section 8.I, the parties agree that, in selecting GNPIPD values to use in applying the Post- Transition Date

8

Formula and in determining which invoices are to be recalculated and which are not following the release of updated GNPIPD values, they will follow the same procedures as are set forth for the GNPIPD adjustment factor in paragraphs c and d of Section 8.I of this Increment One Capacity Agreement.

D. Full and Final Settlement of PPI Dispute.

Provided that the condition precedent set forth in the following paragraph of this Section 3.D is satisfied, this Increment One Capacity Agreement constitutes full and final settlement of the respective claims of HECO and Kalaeloa arising out of the PPI Dispute. Subject only to the satisfaction of such condition precedent, and immediately upon the occurrence of such satisfaction, Sections 3.A, 3.B and 3.C shall come into effect and thereupon both HECO and Kalaeloa shall be deemed to have released the other from all claims arising out of the PPI Dispute.

The condition precedent referenced in the preceding paragraph of this Section 3.D is the first to occur of either of the following: (i) the satisfaction of the conditions precedent to the effectiveness of Sections 2 and 4 through 9 of this Increment One Capacity Agreement, as set forth in Section 13 of this Increment One Capacity Agreement; or (ii) the occurrence of both (aa) Lender Approval by the Lender Approval Deadline pursuant to Section 13 of this Increment One Capacity Agreement and (bb) the issuance, by the PUC Approval Deadline (as defined in said Section 13), of a “final non-appealable order from the Public Utilities Commission” (as defined in Section 11.C of the Increment One Capacity Agreement) that either (yyy) declares that the change in the calculation of the Additive Component of the Energy Charge in Section 5.1 of the Power Purchase Agreement pursuant to the settlement of the PPI Dispute set forth in this Section 3 of the Increment One Capacity Agreement (the “Additive Calculation Settlement”) does not require Public Utilities Commission approval or (zzz) approves the Additive Calculation Settlement. If the foregoing condition precedent has not been satisfied within the respective time periods provided in the preceding sentence, Sections 3.A, 3.B and 3.C shall be null and void ab initio unless otherwise agreed in writing by the parties.

E. No Prejudice.

The parties acknowledge that, with regard to the claims arising out of the PPI Dispute, this Section 3 of the Increment One Capacity Agreement was an attempt to settle a dispute. Therefore, this Increment One Capacity Agreement, and any negotiations, communications or procedures leading up to this Increment One Capacity Agreement shall not in any way be deemed to waive, limit, or prejudice positions previously taken, or that may be taken in the future, by either HECO or Kalaeloa with respect to the PPI Dispute or be admissible in any dispute resolution proceedings arising out of the PPI Dispute if Sections 3.A, 3.B and 3.C of this Increment One Capacity Agreement never become effective.

4. Rates for Purchase.

Subject to the other provisions of the Power Purchase Agreement and to the provisions of Section 3 above, HECO shall, from and after the Increment One Capacity In-Service Date, accept and pay for electrical energy generated by the Facility and delivered to HECO, and make

9

Capacity Payments to Kalaeloa when such capacity is available, all as set forth in the Power Purchase Agreement as modified by this Section 4. The respective rights and obligations accrued by HECO and Kalaeloa with respect to the payment and receipt of the Energy Charge and Capacity Charges for the period prior to the Increment One Capacity in-Service Date shall continue to be governed by the provisions of the Power Purchase Agreement without giving effect to the amendments and other modifications set forth in this Section 4.

A. Regarding Section 5.1 of the Power Purchase Agreement.

Effective upon the Increment One Capacity In-Service Date, a new Section 5.1E is hereby added to the Power Purchase Agreement to read as follows:

E. Incentive Energy

Notwithstanding any provisions of Section 5.1A to the contrary, for each Contract Year (or part thereof) from and after the Increment One Capacity In-Service Date, the formula for calculating the Energy Charge set forth in Section 5.1A shall apply only to such Net Electrical Energy Output as is necessary to satisfy HECO’s minimum energy purchase obligation for such Contract Year (or part thereof) as set forth in Section 5.1D, and the Energy Charge relating to Incentive Energy shall be computed by the following formula:

Energy Charge = (Fuel Component x (LSFO Actual/LSFO base))

+ (Variable O&M Component x (GNPIPD (current)/GNIPID (base))

+ Additive Component

In the above formula, the terms defined in Section 5.1A shall have the same meanings assigned thereto in Section 5.1A (except that the term “Additive Component” shall have the meaning set forth therein as supplemented by Section 3.A of the Increment One Capacity Agreement once said Section 3.A becomes effective) and the term “Variable O&M Component” shall mean:

0.48 cents/KWH for intervals during which the Facility is dispatched at less than 180,000 KW; and

0.144 cents/KWH for intervals during which the Facility is dispatched at 180,000 KW or above.

Notwithstanding any other provisions of this Agreement to the contrary, HECO shall not accrue any Accumulated Excess Purchases under Section 5.1D in respect of Incentive Energy.

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B. Regarding Section 5.2 of the Power Purchase Agreement.

Effective upon the Increment One Capacity In-Service Date, Section 5.2 of the Power Purchase Agreement is amended as follows:

1. Section 5.2A is amended in its entirety to read as follows:

A. Capacity Charge

(1) Capacity Charge for Baseline Capacity and New Capacity

The Capacity Charge to be paid by HECO to Kalaeloa from and after the Increment One Capacity In-Service Date and thereafter during the remaining Term for Baseline Capacity shall be fixed at a rate of $167.51 per kilowatt year for each kilowatt of Baseline Capacity, as adjusted pursuant to Section 5.2C and 5.2D below, and at a fixed rate of $112.00 per kilowatt year for each kilowatt of New Capacity.

(2) Reduction in Capacity Charge for New Capacity Due to Excessive Steam Sales

Kalaeloa acknowledges that: (a) HECO agreed to conduct the performance evaluation demonstrating the Firm Capacity on the assumption that the Facility export of process steam under the Steam Sales Contract will be equivalent to approximately 80,000 lb/hour (with an appropriate downward correction if the Facility was exporting less than 80,000 lb/hour at the time of the evaluation), because Kalaeloa has represented to HECO that that has been approximately the Facility’s average export of process steam in recent years; (b) the Steam Sales Contract assumes that the Facility will export at least the equivalent of approximately 121,000 lb/hour of process steam; and (c) the ability of the Facility to continuously deliver more than 185,000 KW of electrical energy while simultaneously exporting the equivalent of approximately 121,000 lb/hour of process steam has not been demonstrated.

Accordingly, from the Capacity Charge to be paid for New Capacity the following amounts shall be deducted if, during any one hour of an On-peak Period, (i) the Facility is exporting more than the equivalent of 80,000 lb/hour of process steam, (ii) HECO is dispatching (or has properly ordered dispatch of, whether verbally or electronically) the Facility at more than 180,000 KW of electrical energy and (iii) the Facility is unable to continuously deliver for the full duration of the HECO Dispatch the lesser of (aa) the Baseline Capacity plus the New Capacity and (bb) the amount of Net Electrical Energy Output HECO sought to dispatch. (The difference between (x) the Baseline Capacity plus the New Capacity minus (y) the average amount of Net Electrical Energy Output delivered during a one-hour period, or 4,000 KW, whichever is less, is

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referred to herein as the “Capacity Gap.”) The reduction shall be $0.306849 for each kilowatt multiplied by the number of kilowatts in the largest Capacity Gap that occurs during each On-peak Period of the Contract Year, up to a maximum reduction of $1,228 per On-peak Period or $448,000 in the aggregate in any Contract Year.

(3) [RESERVED]

(4) Further Reduction From Capacity Charge

If any portion of the Capacity For Which Capacity Charges Are Being Incurred in excess of ten (10) MW is unavailable continuously for thirty (30) days or more other than for routine scheduled maintenance preapproved by HECO, a reduction in the Capacity Charge shall be made for the total period during which such capacity is unavailable in accordance with Attachment W (Example I). If any portion of Capacity For Which Capacity Charges Are Being Incurred of ten (10) MW or less is unavailable continuously for more than one hundred twenty (120) days, a reduction in the Capacity Charge shall be made for the total period during which such capacity is not available in accordance with Attachment W (Example II). For purposes of calculating the foregoing reduction in the Capacity Charge, unavailable capacity shall be counted first against New Capacity up to the amount of New Capacity, and then against Baseline Capacity up to the amount of Baseline Capacity. Once reductions in the Capacity Charge are being effectuated pursuant to this Section 5.2A(4), no other reductions in the Capacity Charge for New Capacity shall be made pursuant to Sections 5.2A(2) and (3).

(5) Payment and Reduction

The Capacity Charge is payable in advance monthly installments. In the event that a reduction in the Capacity Charge is required by the foregoing provisions, the amount shall be deducted from the amount of the Monthly Invoice next due to Kalaeloa. If, at end of Term, there remains an amount that has not been deducted from the amounts due under Monthly Invoices, Kalaeloa shall promptly pay to HECO such undeducted amounts.

2. Sections 5.2B(1) and (2) are deleted in their entirety.

5. Operating Thermal Threshold and Liquidated Damages.

Effective upon the Increment One Capacity In-Service Date, the following is added to the Power Purchase Agreement as a new Article XXIV:

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ARTICLE XXIV – OPERATING THERMAL THRESHOLD AND

LIQUIDATED DAMAGES

24.1 The Facility shall for each Calendar Year beginning with the Calendar Year in which the Increment One Capacity In-Service Date occurs achieve an Operating Thermal Threshold greater than or equal to the Minimum Thermal Threshold. Within thirty (30) days after the end of each Calendar Year, Kalaeloa shall provide HECO with a written report documenting the Operating Thermal Threshold actually achieved by Kalaeloa during such Calendar Year and a copy of the annual notice filed by Kalaeloa pursuant to 18 CFR Part 292 demonstrating that the Facility is a Qualifying Facility.

24.2 If the Facility fails to achieve the Minimum Thermal Threshold in any Calendar Year, Kalaeloa shall pay, as HECO’s sole and exclusive remedy for such failure, except in cases of willful misconduct or cases in which HECO may have a claim to equitable relief, liquidated damages to HECO as follows: if such failure occurs during (i) the Calendar Year that commences with the Increment One Capacity In-Service Date, Kalaeloa shall pay liquidated damages to HECO in an amount equal to fifty percent (50%) of the Annual New Capacity Charge for such Calendar Year; (ii) a Calendar Year immediately following a Calendar Year during which Kalaeloa achieved the Minimum Thermal Threshold, Kalaeloa shall pay liquidated damages to HECO in an amount equal to fifty percent (50%) of the Annual New Capacity Charge; and (iii) a Calendar Year immediately following a Calendar Year during which Kalaeloa also failed to achieve the Minimum Thermal Threshold, Kalaeloa shall pay liquidated damages to HECO in an amount equal to one hundred percent (100%) of the Annual New Capacity Charge. For purposes of this Section 24.2, the Annual New Capacity Charge that forms the basis for the liquidated damages of 50% or 100% to be assessed shall be the Annual New Capacity Charge computed without regard to any payment imposed by this Section 24.2 and any other deductions or reductions that may apply, for the Calendar Year during which such failure occurred.

24.3 Payment of liquidated damages to HECO under this Article XXIV is due thirty (30) days after written demand therefor from HECO.

24.4 The respective rights and obligation of HECO and Kalaeloa under this Article XXIV are intended to address new circumstances that have arisen since the initial execution of this Agreement. Accordingly, payments of liquidated damages as a consequence of this Article XXIV are in addition to the liquidated damages provided for under Article VIII of this Agreement and are not subject to the limitations of said Article VIII.

6. Calculation of Equivalent Availability Factor and Equivalent Forced Outage Rate.

Effective upon the Increment One Capacity In-Service Date, the following is added to the Power Purchase Agreement as a new Article XXV:

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ARTICLE XXV

CALCULATION OF EQUIVALENT AVAILABILITY

FACTOR AND EQUIVALENT FORCED OUTAGE RATE

25.1 When neither of the Facility’s combustion turbines is in a reserve shutdown status, the Facility must be able to deliver at least 189,000 KW of Net Electrical Energy Output (or such other Net Electrical Energy Output as is associated with the capacity as may result from Delay Degradation) (“One Hundred Eighty-Nine”), when called for by HECO Dispatch, in order to avoid a derating for purposes of calculating Equivalent Availability Factor and Equivalent Forced Outage Rate. If, when called for by HECO Dispatch during periods when neither of the Facility’s combustion turbines is in reserve shutdown status, Kalaeloa is unable to deliver the lesser of One Hundred Eighty-Nine or the Net Electrical Energy Output as is associated with the capacity actually called for by HECO Dispatch, a derate will be assessed equal in magnitude to One Hundred Eighty-Nine, minus the revenue meter reading (both expressed in terms of kilowatts), for purposes of calculating Equivalent Availability Factor and Equivalent Forced Outage Rate.

25.2 On those occasions when one of the Facility’s combustion turbines is in a reserve shutdown status, the Facility must be able to deliver at least 90,000 KW of Net Electrical Energy Output (or such other Net Electrical Energy Output as is associated with the capacity as may result from Delay Degradation) (“Ninety”), when called for by HECO Dispatch, in order to avoid a derating for purposes of calculating Equivalent Availability Factor and Equivalent Forced Outage Rate. If, when called for by HECO Dispatch during periods when one of the Facility’s combustion turbines is in a reserve shutdown status, Kalaeloa is unable to deliver the lesser of Ninety or the Net Electrical Energy Output as is associated with the capacity actually called for by HECO Dispatch, a derate will be assessed equal in magnitude to Ninety, minus the revenue meter reading (both expressed in terms of kilowatts), for purposes of calculating Equivalent Availability Factor and Equivalent Forced Outage Rate.

25.3 Under this Agreement, the ratios for both Equivalent Availability Factor and Equivalent Forced Outage Rate are to be calculated in accordance with North American Electric Reliability Council (NERC) Generating Availability Data System (GADS) formulas, excluding the applicable seasonal adjustment. As a result, Net Dependable Capacity (“NDC”) and Net Maximum Capacity (“NMC”) are used in calculating Equivalent Planned Derated Hours and Equivalent Unplanned Derated Hours. In all cases, regardless of ambient conditions and degradation (except for the Delay Degradation) in arriving at One Hundred Eighty-Nine or Ninety, as appropriate), NDC and NMC will continue to be One Hundred Eighty-Nine. Deratings that are less than or equal to 2% of the NMC, and/or less than or equal to 30 minutes in duration, will continue to be included as deratings in determining Derated Hours.

25.4 The foregoing provisions of this Article XXV are intended to integrate into this Agreement the clarification and interpretation of this Agreement evidenced in the Agreement to Clarify and Interpret dated March 31, 1997, by and between Kalaeloa

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and HECO, and the aforesaid Agreement to Clarify and Interpret is superseded by this Article XXV and of no further force or effect.

7. Limitation on Certain Reductions in and Deductions from Capacity Payments and on Liquidated Damages.

Effective upon the Increment One Capacity In-Service Date, the following is added to the Power Purchase Agreement as a new Article XXVI:

ARTICLE XXVI

LIMITATION ON CERTAIN REDUCTIONS IN AND DEDUCTIONS

FROM NEW CAPACITY PAYMENTS AND ON LIQUIDATED DAMAGES

26.1 Any other provision of this Agreement to the contrary notwithstanding, for each Contract Year, the sum of the following items shall not be assessed or accrue to the extent such sum exceeds the Annual New Capacity Charge for such Contract Year: the reduction in Capacity Charge for New Capacity pursuant to Section 5.2A(2) and liquidated remedy payable under Article XXIV. HECO acknowledges that it shall not seek any further remedies against Kalaeloa related to such failures, except in cases of willful misconduct or cases in which HECO may have a claim to equitable relief.

26.2 If any amounts owed by Kalaeloa for the reduction in Capacity Charge for New Capacity pursuant to Section 5.2A(2) or liquidated damages payable under Article XXIV are not paid when due, HECO shall have the right to set off any payment due against HECO’s payments of subsequent Monthly Invoices as necessary, provided, however, that the maximum amount set off against any one Monthly Invoice shall be limited to the Capacity Charge for New Capacity payable that month.

8. Other Clarifications, Modifications and Amendments to the Power Purchase Agreement.

Effective upon the Increment One Capacity In-Service Date, the following provisions of the Power Purchase Agreement are deemed to be clarified, modified or amended as set forth in this Section 8:

A. Regarding Section 1.57 of the Power Purchase Agreement

For purposes of applying the “Unit Trips” definition to incidents occurring after the execution of the Increment One Capacity Agreement, the requirement of prior HECO “consultation with Kalaeloa” shall, without limitation, be satisfied by any communication either from the Kalaeloa plant operator to the HECO load dispatcher or vice versa with respect to the trip/shutdown in question regardless of whether or not the communication in question takes place before or after such trip/shutdown event. Such communication (i) need not be made by two-way medium and (ii) shall include any “hot line”, telephone or radio communication. The point of the clarification set forth in this paragraph is that in a trip/shutdown event, it is impracticable to interpret the term “consultation” to require an exchange of views between Kalaeloa and HECO as a condition to HECO action, and that such impracticality should not relieve Kalaeloa of the

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consequences, as set forth elsewhere in the Power Purchase Agreement, of including the trip/shutdown event in question within the definition of “Unit Trips.”

The requirement that HECO “take immediate steps to place an unscheduled generator on-line” shall not operate to exclude from the “Unit Trips” definition a trip/shutdown event if, at the time of the trip/shutdown in question, all generators comprising HECO’s resource system that are available to operate are operating and HECO would have taken immediate steps to place another generator on-line had another generator been available.

An “unscheduled generator” is determined immediately prior to the instant of commencement of the trip/shutdown event and means, in the case of a steam generator, a generator that had not been scheduled by HECO to be on-line for at least another three hours after the time a trip/shutdown event commenced, and in the case of a non-steam generator such as a combustion turbine or internal combustion engine, a generator that had not been scheduled by HECO to be on-line at least another thirty minutes after the time a trip/shutdown event commenced.

The exclusion from the definition of “Unit Trips” of trips/shutdowns “caused by events outside of the Facility” shall not operate to preclude from the “Unit Trips” definition trips/shutdowns caused by events occurring outside the Facility through which a facility like the Facility should reasonably be expected, as a result of employing Good Engineering and Operating Practices, to remain synchronized and continue operation without the occurrence of a trip/shutdown event.

B. Regarding Section 3.3H of the Power Purchase Agreement.

In the event Kalaeloa requires HECO to purchase the Facility pursuant to Section 3.3H, the parties agree that the phrase “original equity investment” does not include the Investments to Meet Intended Design Capability.

C. Regarding Section 6.1 of the Power Purchase Agreement.

The first full paragraph of Section 6.1 is amended in its entirety to read:

By the fifth (5th) working day (i.e. excluding Saturdays, Sundays and legal holidays of either the federal government or the Hawaii state government) of each Calendar Month, HECO shall provide Kalaeloa with the appropriate data in writing or electronically for Kalaeloa to compute the Energy Charge in the preceding Calendar Month as determined in accordance with this Agreement.

The remainder of Section 6.1 is unchanged.

D. Regarding Section 7.2B(1) of the Power Purchase Agreement.

In the event HECO exercises its right to purchase the Facility pursuant to Section 7.2B(1) of the Power Purchase Agreement, the parties agree that the fair market value of the

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Facility shall be determined as if the Investments to Meet Intended Design Capability had not been made.

E. Regarding Section 23.15 of the Power Purchase Agreement.

Section 23.15 of the Power Purchase Agreement is amended by adding the following new Subsection 23.15.C:

C. Discontinuation of Index.

Should an index referred to herein, including but not limited to GNPIPD, be discontinued during the Term, HECO and Kalaeloa agree to select a new index that is most similar to the discontinued index in content and concept and to make a proper transition thereto consistent with the intent hereof.

F. Regarding Article XXIII of the Power Purchase Agreement.

Article XXIII of the Power Purchase Agreement is amended by adding the following as new Sections 23.18 through 23.20:

23.18 Steam Sales Contract Monthly Report

Not more than 30 days following the end of each Calendar Month, Kalaeloa shall provide HECO with a written report setting forth for each one-hour interval during each On-peak Period during such Calendar Month the amount of process steam exported by the Facility pursuant to the Steam Sales Contract and the average (the “On-peak Monthly Steam Average”) export of process steam for all such one-hour intervals during the month (the “Steam Sales Monthly Report”). If any Steam Sales Monthly Report indicates that the On-peak Monthly Steam Average exceeds 80,000 lb/hour that month, then the Steam Sales Monthly Report shall also include an explanation of the reasons for the On-peak Monthly Steam Average exceeding 80,000 lb/hour and a projection for the Calendar Year of the amount of process steam to be exported by the Facility pursuant to the Steam Sales Contract. If any such yearly projection indicates that the On-peak Monthly Steam Average is projected to exceed 80,000 lb/hour in any Month remaining in such Calendar Year, then the Steam Sales Monthly Report shall also include an explanation of the reasons therefor.

23.19 Additional Covenant Concerning Steam Sales Contract

If any Steam Sales Monthly Report indicates that the counterparty to the Steam Sales Contract has increased its take of process steam from the Facility beyond the equivalent of 80,000 lb/hour during any On-peak Period resulting in or contributing to a derating of the Facility’s capability below the Firm Capacity (as may be reduced by any Delay Degradation), or that said counterparty is projected to increase its take of process steam from the Facility beyond the equivalent of 80,000 lb/hour during the Calendar Year such that the increased take of steam may result in deratings of the Facility’s capability below

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the Firm Capacity (as may be reduced by any Delay Degradation) during On-peak Periods, then Kalaeloa shall promptly take such actions as it determines to be appropriate to eliminate the occurrence of such deratings below the Firm Capacity (as may be reduced by any Delay Degradation) and shall report to HECO on its efforts to eliminate the occurrence of such deratings below the Firm Capacity (as may be reduced by any Delay Degradation).

In the event the counterparty’s take of process steam from the Facility beyond the equivalent of 80,000 lb/hour during the Calendar Year results in or contributing to deratings below the Firm Capacity (as may be reduced by any Delay Degradation) during more than thirty (30) On-peak Periods during that Calendar Year, Kalaeloa shall employ all commercially reasonable efforts to eliminate such process steam-related deratings below the Firm Capacity (as may be reduced by any Delay Degradation) or to induce such counterparty to limit its take of process steam from the Facility to the equivalent of 80,000 lb/hour during On-peak Periods, provided that Kalaeloa is not required to induce any limitation that would have the effect of causing the Facility to fail to achieve the Minimum Thermal Threshold or be a Qualifying Facility.

23.20 Financial Compliance

Kalaeloa shall provide or cause to be provided to HECO on a timely basis, as reasonably determined by HECO, all information, including but not limited to information that may be obtained in any audit referred to below (the “Information”), reasonably requested by HECO for purposes of permitting HECO and HEI to comply with the requirements of (a) Interpretation No. 46 (revised December 2003) of the FASB, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51 (“FIN No. 46R”), (b) Section 404 of the Sarbanes-Oxley Act of 2002 (“SOX 404”) and (c) all clarifications, interpretations and revisions of and regulations implementing FIN No. 46R and SOX 404 issued by the FASB, Securities and Exchange Commission, the Public Company Accounting Oversight Board, Emerging Issues Tax Force or other governing agency. In addition, if required by HECO in order to meet its compliance obligations, Kalaeloa shall allow HECO or its independent auditor to audit, to the extent as is reasonably required, Kalaeloa’s financial records, including its system of internal controls over financial reporting; provided that HECO shall be responsible for all costs associated with the foregoing, including but not limited to Kalaeloa’s reasonable internal costs. HECO shall limit access to such Information to persons involved with such compliance matters and restrict persons involved in HECO’s monitoring, dispatch or scheduling of Kalaeloa and/or the Facility, or the administration of the Power Purchase Agreement, from having access to such Information, and persons reviewing such Information shall not participate in negotiations of amendments, modifications or clarifications of the Power Purchase Agreement (unless such participation is approved, in writing in advance, by Kalaeloa).

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HECO shall, and shall cause HEI to, maintain the confidentiality of the Information as provided in this Section 23.20. HECO may share the Information on a confidential basis with HEI and the independent auditors and attorneys for HECO and HEI. (HECO, HEI and their respective independent auditors and attorneys are collectively referred to in this Section 23.20 as “Recipient.”) If either of HEI or HECO, in the exercise of their respective reasonable judgments, concludes that consolidation or financial reporting with respect to Kalaeloa and/or this Power Purchase Agreement is necessary, HEI and HECO each shall have the right to disclose such of the Information as HEI or HECO, as applicable, reasonably determines is necessary to satisfy applicable disclosure and reporting or other requirements and give Kalaeloa prompt written notice thereof (in advance to the extent practicable under the circumstances). If HEI or HECO disclose Information pursuant to the preceding sentence, HEI and HECO shall, without limitation to the generality of the preceding sentence, have the right to disclose Information to the Public Utilities Commission and the Division of Consumer Advocacy of the Department of Commerce and Consumer Affairs of the State of Hawaii (“Consumer Advocate”) in connection with the Public Utilities Commission’s rate-making activities for HECO and other HEI affiliated entities, provided that, if the scope or content of the Information to be disclosed to the Public Utilities Commission exceeds or is more detailed than that disclosed pursuant to the preceding sentence, such Information will not be disclosed until the Public Utilities Commission first issues a protective order to protect the confidentiality of such Information. Neither HECO nor HEI shall use the Information for any purpose other than as permitted under this Section 23.20.

In circumstances other than those addressed in the immediately preceding paragraph, if any Recipient becomes legally compelled under applicable law or by legal process (e.g., deposition, interrogatory, request for documents, subpoena, civil investigative demand or similar process) to disclose all or a portion of the Information, such Recipient shall undertake reasonable efforts to provide Kalaeloa with prompt notice of such legal requirement prior to disclosure so that Kalaeloa may seek a protective order or other appropriate remedy and/or waive compliance with the terms of this Section 23.20. If such protective order or other remedy is not obtained, or if Kalaeloa waives compliance with the provisions at this Section 23.20, Recipient shall furnish only that portion of the Information which it is legally required to so furnish and to use reasonable efforts to obtain assurance that confidential treatment will be accorded to any disclosed material.

The obligation of nondisclosure and restricted use imposed on each Recipient under this Section 23.20 shall not extend to any portion(s) of the Information which (a) was known to such Recipient prior to receipt, or (b) without the fault of such Recipient is available or becomes available to the general public, or (c) is received by such Recipient from a third party not bound by an obligation or duty of confidentiality.

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G. Regarding Attachment A of the Power Purchase Agreement.

Attachment A to the Power Purchase Agreement is deemed replaced in its entirety by Attachment A to this Increment One Capacity Agreement.

H. Regarding Attachment W of the Power Purchase Agreement.

Attachment W to the Power Purchase Agreement is deemed replaced in its entirety by Attachment W to this Increment One Capacity Agreement.

I. Regarding the GNPIPD adjustment factor.

Where the Power Purchase Agreement provides for adjustment of dollar values in accordance with the GNPIPD adjustment factor, including the dollar values for the Non-Fuel Component of the Energy Charge and the dollar value for the minimum energy purchase shortfall calculations, the GNPIPD adjustment factor shall be calculated as follows:

a. The GNPIPD adjustment factor shall be calculated by dividing the previous year’s fourth quarter Final GNPIPD value by the fourth quarter 1987 Final GNPIPD value.

b. In calculating the GNPIPD adjustment factor, the previous year’s fourth quarter Final GNPIPD value and the fourth quarter 1987 Final GNPIPD value shall be numbers published by U.S. Bureau of Economic Analysis (“BEA”).

c. In calculating the GNPIPD adjustment factor, both the previous year’s fourth quarter Final GNPIPD value and the fourth quarter 1987 Final GNPIPD value shall be selected from the same BEA publication release to ensure that the numbers were determined using consistent BEA approved methodologies for both GNPIPD values. HECO and Kalaeloa recognize that the BEA routinely reviews and, as it deems appropriate, updates past GNPIPD quarterly values. Such reviews and updates may cause the fourth quarter 1987 Final GNPIPD value to change during the term of the Power Purchase Agreement. Such reviews and updates will not cause a recalculation of invoices issued prior to the release of the updated GNPIPD values.

d. The BEA typically publishes the previous year’s fourth quarter Final GNPIPD value about three months following the previous year end. Invoices of capacity and energy delivered in each month of the current year shall utilize the published previous year’s fourth quarter Final GNPIPD value. The invoices for capacity and energy delivered in the current year that are issued prior to the BEA publishing of the previous year’s fourth quarter Final GNPIPD value (typically involving the January and February capacity and energy deliveries) will be calculated using the GNPIPD adjustment factor used during the previous year, and then recalculated following BEA publishing of the previous year’s fourth quarter Final GNPIPD value.

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J. Regarding Attachments D and R of the Power Purchase Agreement.

No modifications to Attachments D and R to the Power Purchase Agreement are required as a result of this Increment One Capacity Agreement, and said Attachments D and R remain applicable to the Facility after the Increment One Capacity In-Service Date.

9. Other Terms Unchanged.

All of the terms and conditions of the Power Purchase Agreement that are not altered, amended or replaced by the provisions of this Increment One Capacity Agreement shall remain in full force and effect. In the event that a conflict arises between the Power Purchase Agreement and this Increment One Capacity Agreement, this Increment One Capacity Agreement shall prevail, but the respective documents shall be interpreted to be in harmony with each other where possible.

10. Kalaeloa’s Representations, Warranties and Guarantees of Performance With Respect to New Capacity.

A. As a material inducement to HECO’s decision to enter into this Increment One Capacity Agreement, Kalaeloa represents to HECO that, during recent years, the annual average (measured on a Calendar Year basis) of its export of process steam under the Steam Sales Contract has been equivalent to approximately 80,000 1b/hour and that Kalaeloa has no information indicating that the counterparty to the Steam Sales Contract will increase its annual take of process steam beyond this average.

B. As a material inducement to HECO’s decision to enter into this Increment One Capacity Agreement, Kalaeloa represents, warrants and guarantees to HECO that, from and after the Increment One Capacity In-Service Date, the Facility will, during each Calendar Year, achieve the Minimum Thermal Threshold, and, as HECO’s sole remedy therefor, except in cases of willful misconduct or in cases in which HECO may have a claim to equitable relief, Kalaeloa shall pay liquidated damages as set forth in Article XXIV of the Power Purchase Agreement.

C. As a material inducement to HECO’s decision to enter into this Increment One Capacity Agreement, Kalaeloa represents, warrants and guarantees to HECO that the Investments to Meet Intended Design Capability and the construction and operation thereof, (1) have been performed with all required permits, licenses, approvals and other governmental authorizations needed to construct said improvements and operate the Facility with said improvements, (2) have not been and shall not be included in the meaning of the phrase “original equity investment” for purposes of calculating the purchase price as described in Section 3.3H of the Power Purchase Agreement, (3) have not been and shall not be included in calculating the fair market value of the Facility for purposes of Section 7.2B(1) of the Power Purchase Agreement, (4) have been accepted as part of the Facility by the operator under the Operating, Maintenance and Repair Agreement, and (5) do not interfere with, limit or detract from the representations, warranties and guarantees made by Kalaeloa in the Power Purchase Agreement. Upon request by HECO, Kalaeloa shall provide or make available to HECO at the Facility documents or other evidence demonstrating that Kalaeloa has met the foregoing representations, warrantees and guarantees. Kalaeloa has delivered to HECO that certain letter dated

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June 30, 2004, a copy of which is attached hereto as Exhibit 3, setting forth calculations of (i) the purchase price for the Facility for purposes of said Section 3.3H and (ii) the fair market value of the Facility for purposes of said Section 7.2B(1), similar in format to the letters from Kalaeloa to HECO dated March 31, 2000 and April 4, 1997, which calculations demonstrate that the Investments to Meet Intended Design Capability are not included in calculating either the purchase price for the Facility for purposes of said Section 3.3H or the fair market value of the Facility for purposes of said Section 7.2B(1).

11. Regulatory Approval.

A. The parties shall use good faith efforts to obtain, as soon as practicable, a final non-appealable order from the Public Utilities Commission that does not contain terms and conditions deemed to be unacceptable to HECO, and is in a form deemed to be reasonable by HECO, in its sole, but nonarbitrary, discretion, approving this Increment One Capacity Agreement and ordering that:

(1) the purchase power costs to be incurred by HECO as a result of this Increment One Capacity Agreement are reasonable;

(2) HECO’s purchase power arrangements under this Increment One Capacity Agreement, pursuant to which HECO will purchase Increment One Capacity from Kalaeloa and may purchase additional energy, are prudent and in the public interest;

(3) the Fuel Component and the Additive Component of the purchased energy costs and related revenue taxes to be incurred by HECO pursuant to this Increment One Capacity Agreement may be included in HECO’s energy cost adjustment clause to the extent such costs are not included in base rates; and

(4) HECO may include the costs of the Increment One Capacity and the purchased power incurred by HECO pursuant to this Increment One Capacity Agreement in its revenue requirements for ratemaking purposes and for the purposes of determining the reasonableness of HECO’s rates.

B. Notwithstanding any other provisions of this Increment One Capacity Agreement to the contrary, HECO’s obligations under this Increment One Capacity Agreement to purchase power delivered by Kalaeloa by virtue of the Increment One Capacity and to pay the Capacity Charge for the Increment One Capacity, and any and all obligations of HECO which are ancillary to that purchase and that payment, are all contingent upon obtaining the order described in this Section 11. (Such order is referred to hereinbelow as the “PUC Approval Order”.)

C. As used in Section 11.A. above, the term “final non-appealable order from the Public Utilities Commission” means a PUC Approval Order (a) that is considered to be final by HECO, in its sole discretion, because HECO is satisfied that no party to the subject Public Utilities Commission proceeding intends to seek a change in such PUC Approval Order through motion or appeal, or (b) that is not subject to appeal to any Circuit Court of the State of Hawaii or the Supreme Court of the State of Hawaii, because the thirty (30) day period permitted for such an appeal has passed without the filing of notice of such an appeal, or (c) that was affirmed

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on appeal to any Circuit Court of the State of Hawaii or the Supreme Court, or the Intermediate Appellate Court upon assignment by the Supreme Court, of the State of Hawaii, or was affirmed upon further appeal or appellate process, and that is not subject to further appeal, because the jurisdictional time permitted for such an appeal (and/or further appellate process such as a motion for reconsideration or an application for writ of certiorari) has passed without the filing of notice of such an appeal (or the filing for further appellate process). Promptly after the issuance of a PUC Approval Order, HECO shall provide Kalaeloa with a copy of such PUC Approval Order together with a written statement as to whether the conditions set forth in (i) Section 11A and (ii) clause (a) of this Section 11C have been satisfied.

D. As used in this Increment One Capacity Agreement, the term “PUC Approval Date” shall be defined as the date of issuance of the PUC Approval Order if HECO provides the written statement referred to in the last sentence of Section 11C to the effect that the condition referred to in clause (a) of Section 11C of this Increment One Capacity Agreement has been satisfied or in the absence of such a written statement:

(1) If a PUC Approval Order is issued and is not made subject to a motion for reconsideration filed with the Public Utilities Commission or an appeal, the PUC Approval Date shall be the date one day after the expiration of the thirty-day period permitted for filing of an appeal following the issuance of the PUC Approval Order.

(2) If the PUC Approval Order became subject to a motion for reconsideration, and the motion for reconsideration is denied or the PUC Approval Order is affirmed after reconsideration, and such order is not made subject to an appeal, the PUC Approval Date shall be deemed to be the date one day after the expiration of the thirty-day period permitted for filing of an appeal following the order denying reconsideration of or affirming the PUC Approval Order.

(3) If the PUC Approval Order, or an order denying reconsideration of the PUC Approval Order or affirming approval of the PUC Approval Order after reconsideration, becomes subject to an appeal, then the PUC Approval Date shall be the date upon which the PUC Approval Order becomes a non-appealable order within the meaning of Section 11C.

12. Entire Agreement.

This Increment One Capacity Agreement and the Power Purchase Agreement, as amended herein, embody the whole agreement and understanding of the parties as to matters described herein and supersede and nullify all prior agreements, arrangements and understandings related to the subject matter of this Increment One Capacity Agreement; provided, however, that nothing in this Section 12 shall cause the Power Purchase Agreement to be invalid or unenforceable against HECO or Kalaeloa on the basis of regulatory action concerning this Increment One Capacity Agreement.

13. Effective Date.

Sections 3.A, 3.B and 3.C of this Increment One Capacity Agreement shall become effective as provided in Section 3.D. Provided the conditions precedent to the effectiveness of Sections 2 and 4 through 9 of this Increment One Capacity Agreement as set forth in the next

23

sentence of this Section 13 have been satisfied, Sections 2 and 4 through 9 hereof shall become effective on the Increment One Capacity In-Service Date. The conditions precedent referenced in the first sentence of this Section 13 are (a) the occurrence of the PUC Approval Date as defined in Section 11D above and (b) the consent to this Increment One Capacity Agreement by ING Capital LLC, as Agent for the “Lenders” under the Amended and Restated Loan and Note Purchase Agreement, dated as of December 10, 1991 (the “Lender Approval”). Kalaeloa shall use good faith efforts to obtain Lender Approval. Should the PUC Approval Date not occur by August 1, 2005 or such later date as HECO and Kalaeloa may agree to by a subsequent written agreement (the “PUC Approval Deadline”), or should the Lender Approval not be obtained within a reasonable period (expected to approximately sixty (60) days) after the full execution of this Increment One Capacity Agreement and the delivery hereof to the Agent (which Kalaeloa agrees to cause to be done promptly after full execution by both parties), but in no event later than January 3, 2005 or such later date as HECO and Kalaeloa may agree to by a subsequent written agreement (the “Lender Approval Deadline”), Sections 2 and 4 through 9 of this Increment One Capacity Agreement shall be null and void ab initio, and HECO and Kalaeloa shall be free of all obligations under said Sections 2 and 4 through 9 and shall pursue no remedies against one another arising out of or related to said Sections 2 and 4 through 9.

14. Settlement of Section 5.2B(2) Dispute.

Provided that the conditions precedent set forth in the following paragraph of this Section 14 are satisfied, this Increment One Capacity Agreement shall constitute full and final settlement of the respective claims of HECO and Kalaeloa under Section 5.2B(2) of the Power Purchase Agreement. Subject only to the satisfaction of such conditions precedent, effective upon the PUC Approval Date, (a) all rights and obligations of HECO and Kalaeloa with respect to the Increment One Capacity and the obligation to make available and pay for same are integrated into and governed solely by this Increment One Capacity Agreement and (b) both HECO and Kalaeloa shall be deemed to have released the other from all further obligations under said Section 5.2B(2) and to have terminated their respective rights thereunder to the extent not incorporated into this Increment One Capacity Agreement.

The conditions precedent referenced in the preceding paragraph of this Section 14 are the following: (i) Lender Approval pursuant to Section 13 of this Increment One Capacity Agreement within the time period provided in or otherwise permitted under said Section 13; and (ii) occurrence of the PUC Approval Date by Augustc 1, 2005, or such later date as HECO and Kalaeloa may agree to by a subsequent written agreement. If the foregoing conditions precedent have not been satisfied within the respective time periods provided in or otherwise permitted under the preceding sentence, the settlement of the respective claims of HECO and Kalaeloa under Section 5.2B(2) of the Power Purchase Agreement as set forth in this Increment One Capacity Agreement shall be null and void ab initio, and HECO and Kalaeloa shall be free to pursue their remedies against one another arising out of their respective claims under Section 5.2B(2) of the Power Purchase Agreement.

The parties acknowledge that, with regard to the claims under Section 5.2B(2) of the Power Purchase Agreement, this Increment One Capacity Agreement and the demonstration in connection therewith were an attempt to settle a dispute. Therefore, this Increment One Capacity Agreement, HECO’s participation in said demonstration, and any negotiations, communications

24

or procedures leading up to this Increment One Capacity Agreement shall not in any way be deemed to waive, limit, or prejudice positions previously taken, or that may be taken in the future, by either HECO or Kalaeloa with respect to Section 5.2B(2) of the Power Purchase Agreement or be admissible in any dispute resolution proceedings arising out of Section 5.2B(2) of the Power Purchase Agreement if Sections 2 and 4 through 9 never become effective.

15. Miscellaneous.

A. The failure of either party to enforce at any time any of the provisions of this Increment One Capacity Agreement, or to require at any time performance by the other party of any of the provisions hereof, shall in no way be construed to be a waiver of such provisions, nor in any way to affect the validity of this Increment One Capacity Agreement or any part hereof, or the right of such party to enforce every such provision.

B. No modification or waiver of all or any part of this Increment One Capacity Agreement shall be valid unless it is reduced to writing which expressly states that the parties thereby agree to a waiver or modification as applicable and signed by both parties.

C. This Increment One Capacity Agreement may be executed in several counterparts and all so executed counterparts shall constitute one agreement, binding on both parties hereto, notwithstanding that both parties may not be signatories to the original or the same counterpart.

D. This Increment One Capacity Agreement and all documents executed and delivered in connection herewith, and all notices and other communications given pursuant to this Increment One Capacity Agreement, may be executed and signatures transmitted electronically via the Internet or facsimile.

IN WITNESS WHEREOF, the parties have executed this Increment One Capacity Agreement by their respective duly-authorized officers as of the date first stated above.

HAWAIIAN ELECTRIC COMPANY, INC.		KALAELOA PARTNERS, L.P.
By	/s/ Thomas C. Simmons	By PSEG Kalaeloa Inc.
	Its Vice President – Power Supply	Its General Partner
By	/s/ Thomas L. Joaquin	By	/s/ Royal Daniel
	Its SVP - Operations		Its Vice President
Executed on: October 12, 2004		Executed on: October 12, 2004

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EXHIBITS

EXHIBIT 1	Letter dated April 21, 2004 (see Recital H)
EXHIBIT 2	Capacity Evaluation Protocol Kalaeloa Cogeneration Facility Case for up to 189 MW identified as “(9/20/04)” (see Recital H)
EXHIBIT 3	Letter dated June 30, 2004 from Kalaeloa to HECO re calculations of the purchase price for the Facility for purposes of said Section 3.3H or the fair market value of the Facility for purposes of said Section 7.2B(1) (see 10C)

ATTACHMENTS

ATTACHMENT A (see 8G)

ATTACHMENT W (see 8H)

HECO Exhibit 10.3

[ Hawaiian Electric Company, Inc. Letterhead ]

EXHIBIT 1

April 21, 2004

VIA FACSMILIE TRANSMISSION (682-4996) AND U.S. MAIL

Mr. Ruedi Tobler

General Manager

Kalaeloa Partners, L.P.

91-111 Kalaeloa Boulevard

Kapolei, Hawaii 96707

Dear Ruedi:

Subject:	KPLP Performance Test for Potential 9 MW Increase
	in Capacity Capability Prior to a C Inspection

As follow-up to our discussion the past few weeks on the above subject, Hawaiian Electric Company, Inc. (HECO) would like to reaffirm that we are facilitating the Kalaeloa Partners, L.P. (KPLP) efforts to demonstrate the capabilities of its Facility prior to a “C” inspection, based on our understanding that the only purpose of the demonstration is to support on-going discussions regarding the potential for an agreement (subject to PUC approval) to increase KPLP’s firm capacity. KPLP plans to collect various plant parameter data, and HECO plans to collect certain revenue meter data, which would be shared in the on-going discussions. There has been no final agreement on a comprehensive performance test protocol, but it is hoped that the data collected under well documented operating modes and conditions can form the basis for a performance test if a firm capacity agreement, which could include a test protocol, results from the on-going discussions. HECO’s willingness to participate in the demonstration is premised on the understanding that its participation (and KPLP’s participation, for that matter) will in no way be deemed to waive, limit, or prejudice positions previously taken, or that may be taken in the future, by either HECO or KPLP with respect to Section 5.2B(2) of the PPA, as amended. In other words, the participation of HECO and KPLP in the demonstration will be considered statements or conduct made in compromise negotiations, and will not be admissible in any arbitration or other legal proceedings regarding or arising out of Section 5.2B(2).

If you have any questions, please let me know.

Sincerely

/s/ Ward D. Saunders

Ward D. Saunders

Power Purchase Contracts Administrator

cc via email:

Tom Simmons

Dan Ching

Stephanie Gonsalves

EXHIBIT 2

Capacity Evaluation Protocol

Kalaeloa Cogeneration Facility

Case for up to 189 MW

Purpose

The purpose of this evaluation protocol is to set forth a protocol to be used to demonstrate the Facility’s ability to provide additional capacity, up to 189 MW, to the Hawaiian Electric Company, Inc. (“HECO”) system (as measured by HECO’s revenue meters at the Points of Interconnection and with the output corrected to the below agreed upon evaluation conditions which are being used as a proxy to represent reasonable worst case conditions for Facility operations). The results of this evaluation will be used by HECO and Kalaeloa to support current discussions to increase the Firm Capacity.

Capitalized terms used herein and not otherwise defined shall have the meanings ascribed thereto in the Power Purchase Agreement dated as of the 14^th day of October 1988 between KALAELOA Partners, L.P. (“Kalaeloa”) and Hawaiian Electric Company, Inc. (as heretofore amended and clarified, the “PPA”).

No change in the Firm Capacity level from the current 180 MW recognized by HECO will be made by reason of the parties’ agreement upon this protocol.

Test Conditions and Parameters

1. A continuous 48 hour test run of the Facility will be conducted (the “Test”). Any abnormal conditions or equipment failure during the Test which impact the Test results shall cause the Test to end, and in which case the parties after review of the reasons for the Test termination shall arrange the scheduling of another Test by mutual agreement of Kalaeloa and HECO. A Test may be concluded before its 48-hour duration if the determination that enough data has been collected is made jointly by HECO and Kalaeloa.

2. For at least one month prior to the Test, turbine washes shall have continued to be conducted on Friday/Saturday and Saturday/Sunday periods respectively.

3. The commencement of the Test shall be scheduled such that at the conclusion of the Test, the HRSGs will be in their most fouled state in the cleaning cycle and due for wash according to the then current normal wash cycle. The HRSGs shall not be washed during the 48-hour period just prior to the commencement of the Test.

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4. The Test shall be conducted just prior to a “C” inspection being due for at least one of the combustion turbines. The other combustion turbine should be at the mid point (approximately at least one year) following its last “C” inspection. Given the historical and future plans for “C” inspection intervals at one per year and an approximately two year interval between “C” inspections for a given combustion turbine this scenario should closely approximate the worst case Facility operating regime relative to operational degradation of the two combustion turbines.

5. The maximum turbine inlet temperature (“TIT”) setpoint shall be 1854 Deg. F. Actual TIT may vary by no more than a couple degrees from the setpoint due to normal control system variations.

6. The maximum steam injection to fuel ratio (lbs of steam/lb of fuel) shall not exceed 1.5 unless a greater amount is needed to meet the air quality permit requirements of the Facility. Operating conditions shall meet the requirements of all applicable permits.

7. Steam export to Tesoro during the Test shall be at least 80,000 lb/hr or the value thereof necessary for the Facility to achieve PURPA Qualifying Facility requirements, whichever is greater. If the steam export is less than 80,000 lb/hr, a downward correction will be applied pursuant to the Evaluation of Test Results section of this document.

8. The power factor during the Test shall be as close as possible to 0.85 at full load for at least 30 to 60 minutes, if HECO Dispatch can accommodate such, to ensure the Facility is able to operate with the increased load at the contractual minimum power factor required by the PPA. The power factor during the Test may range anywhere within the specifications of Section 2.1D of the PPA.

9. The Facility shall operate at normal and representative operating conditions under control of HECO Dispatch consistent with the terms and conditions of the PPA. Operation during the Test outside of these conditions shall entitle Kalaeloa to a new Test.

10. Kalaeloa shall perform the Test in full compliance with all of its current operating permits, including the Covered Source Permit. Where no continuous emission monitoring is required by permit to document compliance, Kalaeloa shall, during the Test, demonstrate to HECO’s satisfaction that the Facility is continuously capable of complying with its Covered Source Permit at all output levels between 65MW and the capacity capability demonstrated by the Test.

11. Either prior to the Test or as part of the analysis in the evaluation period following the Test, Kalaeloa shall provide written documentation to HECO’s satisfaction that all Facility modifications made subsequent to the initial design and construction of the Facility are in compliance with applicable environmental laws and regulations, and permits so that the Facility can operate under HECO Dispatch with all modifications subsequent to its original design and construction, and the operation of the Facility under HECO Dispatch for future periods at the capability level

2

demonstrated in the Test will not be limited or restricted in any way as a result of a condition contained in any permit.

12. HECO’s evaluation of the capability level demonstrated under this Test shall be based on the minimum average capacity level that the Facility is able to sustain over each One Clock Hour Average (as defined below), as recorded by the revenue meters after the adjustment by any correction factor as discussed herein, in which the Facility is being dispatched at full load during the Test and in which the Facility adheres to all operational parameters set forth herein. Capacity data shall only be valid once the Facility is stable at full load. Stable full load is defined by operation at full firing temperature and inlet guide vanes at 0 +/- 0.3, and that these conditions exist for at least one hour prior to the measurement hour in order to allow the Facility’s steam cycle to reach equilibrium. Operation at this mode shall be continuous at the discretion of HECO’s Load Dispatcher. These values are used to mitigate any short-term variations and to correspond to hourly average Facility supplemental data used for corrections of the results to the Test results.

13. Kalaeloa shall provide a certificate of calibration for all instrumentation pertinent to the operational parameters listed herein.

14. Kalaeloa shall provide written confirmation that no abnormal events occurred during the Test with the various Facility equipment and that the operating modes were within a range of that can be sustained on a continuous mode of operation under HECO Dispatch.

General Information

1. The Facility shall be operated by ALSTOM personnel.

2. HECO’s Load Dispatcher shall allow operation of the Facility at full load as much as practical consistent within dispatch requirements of the HECO system. This can include dispatch of the Facility at the Net Electrical Energy Output as low as 65,000 KW. Testing can be interrupted or terminated at any time by any party should such be necessary to protect the safety of personnel, equipment or system stability but shall be re-commenced once such situation is rectified.

3. HECO may, at its discretion, dispatch observers to the Facility to monitor testing as HECO deems necessary. HECO’s observers shall not interfere with operations, nor shall they direct/supervise ALSTOM’s operators in any manner. However, should they find issues that may compromise the quality of the testing or data, such issues shall be discussed with ALSTOM management and Kalaeloa.

4. Following are contact people for each organization. Additional contact information for the Facility will be provided upon request:

• Contact person for HECO is Ward Saunders – Contract Administrator

• Contact person for Kalaeloa is Ruedi Tobler - General Manager

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• Contact person for ALSTOM is Mike Rossio – Operations Manager

5. Data shall be collected using installed Facility instrumentation, except as listed under “Evaluation of Test Results” item # 1.

Test Set Up

1. First test run shall start on Wednesday, April 21, 2004 at 13:00 and shall end on Friday, April 23, 2004 at 13:00.

2. Additional testing, if necessary, shall be conducted as agreed to by HECO and Kalaeloa.

3. Normal and routine turbine, compressor and HRSG washing schedules shall be followed between the time this Test procedure is agreed and conclusion of Testing and in no case shall normal washing of the turbines, compressors and HRSG’s actually occur more frequently than weekly with the exception of daily on-line compressor washes.

4. Normal full load operating conditions of the Facility as follows:

• evaporative coolers in service

• stack heat exchangers in service

• fuel: LSFO (specification sheet attached)

• variable inlet guide vane (“VIGV”) setting: zero

• TIT setpoint: 1854F

• steam injection: minimum steam-to-fuel ratio 1.3, maximum 1.5 or greater if needed to maintain emissions within permit limits.

• process steam total: as needed by Tesoro

• Power Factor: as dispatched by HECO between 0.85 lagging to 1.0

5. Data shall be collected by the Facility’s data acquisition system.

KALAELOA Procedure

1. Start at 12:00 on day of Test by taking the Facility to full load if consistent with load dispatch requirements.

2. Check to see that performance computer is not locked up, and verify that fuel data are updated.

3. Take Facility off Energy Management System (“EMS”) with concurrence of HECO’s Load Dispatcher and set at baseload conditions: TIT = 1854 °F, max., VIGV at 0°, additive at normal rate, process steam as needed by Tesoro.

4

4. Allow Facility to stabilize at the above conditions until 1:00 p.m. at which time print out the following Praut diagrams:

• P02

• P06

• P04

• P09

• P12

• P20

• P25

• P26

• P27

• P37

• Bar 16

5. If conditions appear stable about 13:00, call HECO’s Load Dispatcher and declare that Testing is under way. Make entry in log book.

6. One hour after start of Test, print out the same data sheets as listed above. Also, around that time, take a fuel sample from LSFO forwarding system.

7. Test will run 48 hours from that point. If HECO needs the Facility back on EMS, do so and make a note in the log. Continue to respond to HECO’s load needs as per normal operating practices.

8. If operating conditions change such that Facility load drops below full load, make an entry in the log book indicating time that such reduction started, reason for reduction, and print out any PRAUT data that may help provide information on this type of condition. When the Facility is restored to full load, make the appropriate entry in the log book.

9. Hourly, check that RADARS is continuing with data collections.

10. Log time whenever fuel tanks are switched. Take a fuel sample at LSFO forwarding about 1 hour after the tanks are switched.

Evaluation of Test Results

1. HECO shall poll its revenue meters (KW and KVAR) and make results available to Kalaeloa soon after the Test (and in any event within 3 working days).

2. The full load minimum One Clock Hour Average during each of the 48 hours of the test shall establish the uncorrected capacity of the Facility. The One Clock Hour Average is defined as the four consecutive 15-minute periods beginning with the reading for the 15 minute period that ends at 15 minutes past the hour. These values are used to mitigate any short-term variations and to correspond to hourly average Facility supplemental data used for corrections to the capacity measured during the Test.

3. For the one clock hour used for analysis, the One Clock Hour Average KW output of each of the three turbines shall be corrected to the following parameters as

5

applicable in accordance with the correction factors determined from the charts to be provided to HECO which include the ASHRAE design conditions determined at 0.4% annual percentile for Barbers Point NAS (now Kalaeloa National Weather Service site) (the “ASHRAE Design Conditions”):

Variable	-	Corrected to:
Compressor Inlet Temperature		77F. Based on ASHRAE Design Conditions of 76F wet bulb, 86F coincident dry bulb, for GT correction with evaporative coolers in service
Ambient Temperature		86F. Based on ASHRAE Design Conditions of 76F wet bulb, 86F coincident dry bulb for ST correction
Ambient Humidity	-	64%. Based on ASHRAE design conditions of 76F wet bulb, 86F coincident dry bulb
Ambient Pressure	-	14.8 psia. Average barometric pressure for August 15 to September 15 at 13:00 (from Kalaeloa’s operational data)
Power Factor		0.85 lagging
Export Steam		up to 80,000 lbs/hr (or value necessary for Facility to achieve PURPA requirements). No correction if above 80,000 lb/hr.

If the actual temperature and humidity conditions exceed the ASHRAE Design Conditions, no corrections will be made to the KW output of any of the three turbines. The ASHRAE Design Conditions represent a ceiling for reasonably anticipated worst-case conditions.

The corrected capacity shall be rounded to the nearest MW output with decimal values of 0.50 and higher being round up to the next integer MW value and decimal values of 0.49 or less being rounded down to the next integer MW value and shall be the capability level demonstrated by the Test.

In order to facilitate evaluation of the Test results and the influence of the Facility modifications, the following shall be provided:

Correction curves for CT:

1.) Compressor Inlet Temperature

2.) Power Factor

3.) Ambient Humidity

Correction curves for ST:

1.) Ambient Temperature and Ambient Humidity

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2.) Ambient Pressure

3.) Power Factor

4.) HP steam export

5.) IP steam export

6.) LP steam export

The following data shall be collected by Kalaeloa during the Test to be used for correcting the measured capacity from the Test results to the herein defined reasonable worst-case conditions:

• date (with day of week shown separately)

• date of last “C” inspection for each CT

• date each HRSG last cleaned

• time (13:00)

• Ambient Temperature

• Ambient Humidity

• Ambient Pressure

• evaporative cooler on?

• dispatched at full load?

• TIT

• steam to fuel ratio, each CT

• total steam export to Tesoro

• CT1 MW

• CT2 MW

• total plant MW

• fuel flow, each CT

• steam turbine MW

• steam turbine exhaust pressure.

• steam turbine throttle pressure

• steam turbine throttle temperature

• CT1 stack exhaust temperature

• CT2 stack exhaust temperature

• fuel analysis (including fuel bound nitrogen)

• VIGV data

• listing of all CT washes, compressor washes (on-line and off-line), boiler washes within 45 days of the start of the test.

• list the Equivalent Operating Hours (EOH) of each CT since the last “C” inspection and the EOH of the ST since the last major inspection.

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HECO Exhibit 10.3

EXHIBIT 3

30-Jun-04

Mr. Ward D. Sauders, P.E.

Purchased Power Contract Administrator

Hawaiian Electric Company, Inc.

P.O. Box 2750

Honolulu, HI 96840-0001

Subject: Calculation of Value of the Facility

Dear Ward,

At your request, we have prepared the calculation of the value of the Facility as specified under PPA Sections 3.3 (H) and 7.2 B (1). These calculations include the outstanding principal on the project debt as of June 30, 2004. Since we make quarterly debt service payments, this debt value will be the same until September 30, 2004. Please see the enclosed.

Sincerely,
Kalaeloa Partners, L.P.
By:	PSEG Kalaeloa Inc.
	Its General Partner
By	/s/ Royal Daniel
	Royal Daniel
	Its Vice President

(Enclosures)

Kalaeloa Partners, L.P.

Calculation of PPA 3.3 (H) Value as of 6/30/04

PPA Section 3.3(H) Loss of QF Status

	Outstanding Debt (1)	$	154,198,500
+	Obligations under steam sales contract		—
+	Obligations under site lease		—
+	Turnkey Design/Build Contract		—
+	Operating, maintenance and Repair Contract		—
+	Fuel Supply Contract		—
+	Kalaeloa original equity investment less distributions (2)		—
	Total	$	154,198,500
Footnotes:
(1)	Outstanding Debt:
	Bank loan current balance after quarterly payment on 6/30/04	$	36,579,750
	Institutional loan current balance after quarterly payment on 6/30/04		117,618,750
	Total (As of 6/30/04)	$	154,198,500
(2)	Kalaeloa partners investments and distributions

	Investment		Distribution
1989 Investment	$	1,016,433
1989 Distribution			$	1,612,566
1991 Investment		14,361,064
1992 Distribution				8,711,952
1993 Distribution				5,039,345
1994 Distribution				6,462,618
1995 Distribution				4,566,365
1996 Distribution				—
1997 Distribution				15,188,983
1998 Distribution				9,354,933
1999 Distribution				3,633,000
2000 Distribution				6,168,857
2001 Distribution				10,229,529
2002 Distribution				1,854,003
2003 Distribution				5,832,546
2004 Distribution				1,191,214
	$	15,377,497	$	79,845,911
Investment less Distribution not less than zero. Kalealoa will not include the PSEG purchase price of $54.4 million as an original investment.

Kalaeloa Partners, L.P.

Calculation of PPA 7.2 B (1) Value as of 6/30/04

PPA Section 7.2 B (1), Amendment 3 - HECO’s assumption of Kalaeloa’s Interest upon default

	Outstanding debt (1)	$	154,198,500
+	Other obligations		—
+	Fair market value (FMV) of Facility (2)		110,000,000
-	Stated amount per Amendment		(30,000,000	)
-	$8.5 million x (A/B) (3)		(5,890,729	)
	Total	$	228,307,771
Footnotes:
(1)	See footnote1, previous page
(2)	Hypothetical fair market value based on recent market price indication rounded to the nearest $10,000,000. (actual fair market value would be based on average of 3 appraisals)
(3)	A is outstanding principal	$	154,198,500
	B is initial principal	$	222,500,000
	A/B is:		0.6930
	$8,500,000 x 0.6930	$	5,890,729

HECO Exhibit 10.3

ATTACHMENT W

Capacity Charge Calculation

(Unavailability Adjustment)

This computation is provided as an illustration of how to compute a Capacity Charge adjustment pursuant to Section 5.2A(4) for a hypothetical partial unavailability of the Facility.

Example I – Unavailability in excess of 10MW for 30 days or more

Assumptions:	Baseline Capacity = 180MW
	Capacity Charge for Baseline Capacity = $164.35/KW-yr
	($164.35 is the value effective 12/19/91 per PPA, Restated and Amended Amendment 2, Section 3.)
	New Capacity = 9MW
	Capacity Charge for New Capacity = $112.00/KW-yr
	Capacity deficiency = 38 MW
	Duration of capacity deficiency = 42 days; 0 hours; 0 minutes
	Period of capacity deficiency = April 20 (00:00) – May 31 (24:00)

Impact on Capacity Charge:

Month of April means payment due in April for Energy received by HECO in March and Capacity to be received by HECO in April

Month of April – no impact (capacity paid in advance)

Month of May – no impact (capacity paid in advance)

Month of June – normal payment =

	[	180,000 KW	x	164.35 / KWyr	]	+	[	9,000 KW	x	112.00 / KWyr	]
				12mo / yr						12mo / yr
		= $2,549,250
adjustment to payment =

[	29,000	x	42.00	x	164.35	]	+	[	9,000	x	42.00	x	112.00	]
			365								365

   = $664,422.74 reduction

NOTE:

If deficiency for the same period had been 189 MW, adjustment to the Month of June would be $2,549,250 and the balance ($970,812.27 in this case) would be deducted from Month of July Capacity Charge payment due to Kalaeloa.

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Example II – Unavailability of 10MW or less for more than 120 days

Assumptions:	Capacity deficiency = 10 MW
	Duration of capacity deficiency = 121 days; 0 hours; 0 minutes
	Period of capacity deficiency = April 20 (00:00) – August 18 (24:00)

Impact on Capacity Charge:

Months of April to September- no impact (capacity paid in advance)

Month of September –

normal payment =

[	180,000 KW	x	164.35 / KWyr	]	+	[	9,000 KW	x	112.00 / KWyr	]
			12mo / yr						12mo / yr
	= $2,549,250
	adjustment to payment =

[	1,000	x	121.00	x	164.35	]	+	[	9,000	x	121.00	x	112.00	]
			365								365

= $388,642.05 reduction

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EX-10.4

HECO Exhibit 10.4

AGREEMENT FOR INCREMENT TWO CAPACITY AND

AMENDMENT NO. 6 TO POWER PURCHASE AGREEMENT

BETWEEN

HAWAIIAN ELECTRIC COMPANY, INC.

AND KALAELOA PARTNERS, L.P.

This Agreement for Increment Two Capacity and Amendment No. 6 to Power Purchase Agreement (“Increment Two Capacity Agreement”) is made and entered into as of the date of the last execution hereof, as set forth below the respective signature blocks of the parties, by and between HAWAIIAN ELECTRIC COMPANY, INC., a Hawaii corporation (“HECO”), and KALAELOA PARTNERS, L.P., a Delaware limited partnership (“Kalaeloa”).

RECITALS:

A. HECO and Kalaeloa entered into a Power Purchase Agreement, dated as of October 14, 1988, as amended and clarified by (i) Amendment No. 1 to Power Purchase Agreement dated as of June 15, 1989, (ii) Restated and Amended Amendment No. 2 to Power Purchase Agreement dated as of February 9, 1990, (iii) Amendment No. 3 to Power Purchase Agreement dated as of December 10, 1991, (iv) Agreement to Clarify and Interpret dated as of March 31, 1997, (v) Amendment No. 4 to Power Purchase Agreement dated as of October 1, 1999, and (vi) Confirmation Agreement Concerning Section 5.2B(2) of Power Purchase Agreement and Amendment No. 5 to Power Purchase Agreement executed concurrently herewith, (as so amended and clarified, the “Power Purchase Agreement”), which provides for, among other things, the sale by Kalaeloa and the purchase by HECO of electric energy and capacity from Kalaeloa’s combined cycle oil-fired cogeneration facility located at Barbers Point, Oahu, Hawaii.

B. HECO and Kalaeloa have executed certain letter agreements clarifying the interpretation and/or application of certain provisions of the Power Purchase Agreement, some of which have been incorporated into and superseded by the Increment One Capacity Agreement (as defined hereinbelow).

C. Kalaeloa has commenced the M Upgrade (as defined hereinbelow), and HECO has consented to the M Upgrade pursuant to the Consent and Agreement dated as of December 31, 2003 by and between HECO and Kalaeloa.

D. Kalaeloa and HECO desire to amend the Power Purchase Agreement to provide for up to an additional twenty megawatts (20,000 KW) in capacity beyond the 189,000 KW capacity confirmed in the Confirmation Agreement Concerning Section 5.2B(2) of the Power Purchase Agreement and Amendment No. 5 to the Power Purchase Agreement referenced in Recital A above (the “Increment One Capacity Agreement”).

E. Kalaeloa has completed an assessment of the potential for trips of the entire Facility and has committed to complete certain improvements, if this Increment Two Capacity Agreement becomes effective, in order to reduce the potential for such trips of the

entire Facility, consisting of (a) certain improvements as described in the letter from Kalaeloa to HECO dated July 29, 2004, a copy of which is attached hereto as Exhibit 1, and (b) certain improvements as described in the letter from Kalaeloa to HECO dated October 8, 2004, a copy of which is attached hereto as Exhibit 2.

AGREEMENTS:

NOW, THEREFORE, in consideration of the premises and mutual agreements and covenants contained in this Increment Two Capacity Agreement and for other good and valuable consideration, the receipt and adequacy of which are hereby acknowledged, the parties hereto agree to provide for Increment Two Capacity as follows:

1. Definitions.

Regardless of whether or not the Increment Two Capacity In-Service Date has occurred, (i) capitalized terms used in Sections 3 through 5 and 11 through 15 of this Increment Two Capacity Agreement and defined in Section 2 of this Increment Two Capacity Agreement have the respective meaning given them in Section 2, and (ii) capitalized terms used but not defined in this Increment Two Capacity Agreement have the respective meaning given to them in the Power Purchase Agreement.

2. Regarding Article I of the Power Purchase Agreement.

Effective upon the occurrence of the Increment Two Capacity In-Service Date, Article I of the Power Purchase Agreement is deemed amended by modifying Sections 1.70 and 1.81 to read in their entirety as set forth below, and by adding the definitions set forth below as Sections 1.96 through 1.109:

1.70 Demonstrated Facility Capacity – For purposes of determining the Increment One Capacity, the maximum capacity of 189,000 KW as demonstrated by the data collected and corrected pursuant to the test conducted on April 21, 2004 through April 23, 2004 under the protocol attached as Exhibit 2 to the Increment One Capacity Agreement. For purposes of determining the Increment Two Capacity, the maximum capacity of the Facility as demonstrated by the data collected and corrected pursuant to the Acceptance Test.

1.81 New Capacity – The Increment One Capacity plus the Increment Two Capacity.

* * *

1.96 Acceptance Test – The acceptance test conducted according to the test protocol stated in the Capacity Evaluation Protocol Kalaeloa Cogeneration Facility Post M Upgrade Case for up to 209 MW for Two CTs, a copy of which is attached to the Increment Two Capacity Agreement as Exhibit 3.

1.97 Full Plant Trip – The Unplanned Removal From Service of the Facility’s two combustion turbine generators in circumstances in which the Facility had, at any

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point during the sixty (60) minutes preceding the Unplanned Removal From Service of the first of the combustion turbines to be so removed, been operating with a Net Electrical Energy Output above 180,000 KW.

1.98 Full Plant Trip (Category I) – A Full Plant Trip in which not more than twenty-five (25) minutes and no seconds elapse between the Unplanned Removal From Service of the first of the combustion turbines to be so removed during such Full Plant Trip and the Unplanned Removal From Service of the second of the combustion turbines to be so removed.

1.99 Full Plant Trip (Category II) – A Full Plant Trip (other than a Full Plant Trip (Category I)) in which not more than one hundred eighty (180) minutes and no seconds elapse between the Unplanned Removal From Service of the first of the combustion turbines to be so removed during such Full Plant Trip and the Unplanned Removal From Service of the second of the combustion turbines to be so removed.

1.100 Full Upgraded Capacity – The total of Baseline Capacity, Increment One Capacity and Increment Two Capacity.

1.101 Increment Two Capacity – The increment, at 0.85 power factor, of Demonstrated Facility Capacity up to a maximum of 20,000 KW beyond 189,000 KW.

1.102 Increment Two Capacity Agreement – The Agreement for Increment Two Capacity and Amendment No. 6 to the Power Purchase Agreement by and between HECO and Kalaeloa.

1.103 Increment Two Capacity In-Service Date – Provided the conditions precedent to the effectiveness of Section 2 and Sections 6 through 11 of the Increment Two Capacity Agreement as set forth in Section 15 thereof have been satisfied, the latter of (i) the date on which the Facility as modified by the Increment Two Capacity Upgrade satisfies the Acceptance Test and (ii) the Increment Two Rate Inclusion Date.

1.104 Increment Two Capacity Upgrade – The physical modifications to be made to the Facility so that the Facility is able to deliver the Increment Two Capacity under HECO Dispatch.

1.105 Increment Two Rate Inclusion Date – The effective date of an interim or final order (whichever is first) of the Public Utilities Commission in a HECO general rate case using a 2005 calendar year test year that includes in HECO’s base electric rates the additional purchased power costs (including the Capacity Charge for the Increment Two Capacity and the Variable O&M Component of the Energy Charge) incurred by HECO pursuant to the Increment Two Capacity Agreement.

1.106 M Upgrade – The physical modifications to the Facility authorized to be commenced pursuant to the Consent and Agreement dated as of December 31, 2003, by and between HECO and Kalaeloa.

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1.107 On-peak EFOR – For each Contract Year, the ratio for the Equivalent Forced Outage Rate for the On-peak Period hours during such Contract Year (expressed as a percent) set forth in Attachment C to this Agreement, as modified by the letter dated October 30, 1997, which represents the time (in hours) during the On-peak Period hours during such Contract Year that the Facility (Baseline Capacity plus New Capacity) is unavailable for service, either totally or partially due to forced outages or deratings (other than Delay Degradation) to the total On-peak Period hours during such Contract Year calculated in accordance with the most current formula defined by NERC GADS (less adjustment for unplanned (forced) derated hours during reserve shutdown).

1.108 Prorated Shutdown Capacity – The greater of the capacity of the Facility with one of its combustion turbines not in service (as determined by the Acceptance Test) or 90,000 KW.

1.109 Unplanned Removal From Service – The unscheduled removal from service, other than for routine scheduled maintenance preapproved by HECO, of a combustion turbine generator at the Facility, but not including any such removal caused by a disturbance or condition occurring on HECO’s grid system during which the Facility could not reasonably have been expected to remain synchronized and continue operation notwithstanding the employment of Good Engineering and Operating Practices.

(1) For purposes of this Section 1.109, Good Engineering and Operating Practices will not require that the Facility remain synchronized and continue operation through the following fault conditions:

(a) three phase fault conditions at the Points of Interconnection lasting more than 120 milliseconds,

(b) two phase fault conditions at the Points of Interconnection lasting more than 120 milliseconds, or

(c) single phase fault conditions at the Points of Interconnection lasting more than 2.0 seconds.

A fault condition event shall be deemed to have ended when the voltage has recovered to and remains above 0.83 per unit (equivalent to 66.1 kV as measured line-to-ground) at the Points of Interconnection or as close as practicable thereto (which shall be deemed to be HECO’s Kalaeloa 138 kV Substation). Such voltage level shall be determined by the measurement equipment described in Section 4.G of the Increment Two Capacity Agreement. In the case where reliable data is not available from said measurement equipment, such voltage level shall be determined by interpretation or analysis of data collected from other voltage measuring equipment on the HECO grid and/or at the Facility.

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(2) For purposes of this Section 1.109, Good Engineering and Operating Practices do not require that the Facility remain synchronized and continue operation if protection relay devices that are properly set, reviewed and accepted according to Sections 2.1B or 3.2A(5) herein or Section 4.C of the Increment Two Capacity Agreement, or included in Attachment A hereto, and which operate in accordance with such specifications, have automatically removed all or a part of the Facility from service.

(3) No Unplanned Removal From Service shall be deemed to have occurred if an operator has manually removed one or both combustion turbine generators from service because, in his considered judgment, such condition or disturbance posed an immediate threat of serious damage to an integral part of the Facility despite the fact that none of the Facility’s breakers or protection relay devices automatically removed all or part of the Facility from service, provided that an after-the-fact review of the circumstances verifies that the actions of the operator were consistent with Good Engineering and Operating Practices.

3. HECO Conditions Precedent.

A. General Conditions.

HECO’s obligation to purchase power delivered by Kalaeloa by virtue of the Increment Two Capacity and to pay the portion of the Capacity Charge corresponding to the Increment Two Capacity, and any and all obligations of HECO that are ancillary to that purchase and that payment, are contingent upon the following in form and substance satisfactory to HECO:

(1) The submission to HECO (or, where satisfactory to HECO, making such available for inspection by HECO) in form and substance reasonably satisfactory to HECO of documents or other evidence demonstrating that the Facility following completion of the Increment Two Capacity Upgrade, if operated and maintained in accordance with Good Engineering and Operating Practices, can be reasonably expected to have a useful life at least equal to the Term; provided that conceptual engineering design drawings and specifications of major equipment components, if available, shall be deemed to constitute such evidence;

(2) The submission to HECO (or, where satisfactory to HECO, making such available for inspection by HECO), in form and substance reasonably satisfactory to HECO, of the following on or before the Increment Two Capacity In-Service Date:

(a) Documents or other evidence that Kalaeloa obtained all required permits, licenses, approvals and other governmental authorizations needed to commence construction of each phase of the Increment Two Capacity Upgrade;

(b) Documents or other evidence that Kalaeloa has obtained all currently required permits, licenses, approvals and other governmental authorizations

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needed to operate the Facility following completion of the Increment Two Capacity Upgrade;

(c) Documents or other evidence demonstrating that the Increment Two Capacity Upgrade has been completed in compliance with the terms of this Increment Two Capacity Agreement and with the information submitted pursuant to Section 3A(2) hereof, provided that such documents and evidence may be made available to HECO at the Facility rather than submitted to HECO. Evidence required under this Section shall be submitted or made available by Kalaeloa during or upon the completion of each phase of development (for example, completion of detailed engineering, completion of as-built drawings and receipt of manufacturers’ guarantee performance data). To allow HECO to evaluate the information provided by Kalaeloa, Kalaeloa shall cooperate in such physical inspections of the Facility pursuant to Section 9.1 of the Power Purchase Agreement as may be reasonably required by HECO during and after completion of the Increment Two Capacity Upgrade. In no event shall HECO’s technical review and inspection of the Facility and the Increment Two Capacity Upgrade be deemed to be an endorsement of the design thereof or as any warranty of the safety, durability or reliability of the Facility following completion of the Increment Two Capacity Upgrade nor a waiver of any of HECO’s rights;

(d) Documents or other evidence demonstrating that the improvements described in Exhibit 1 attached hereto (the “Full Plant Trip Reduction Improvements”) have been completed, provided that such documents and evidence may be made available to HECO at the Facility rather than submitted to HECO. To allow HECO to evaluate the information provided by Kalaeloa, Kalaeloa shall cooperate in such physical inspections of the Facility pursuant to Section 9.1 of the Power Purchase Agreement as may be reasonably required by HECO during and after completion of the Full Plant Trip Reduction Improvements. In no event shall HECO’s technical review and inspection of the Facility and the Full Plant Trip Reduction Improvements be deemed to be an endorsement of the design thereof or as any warranty of the safety, durability or reliability of the Facility following completion of the Full Plant Trip Reduction Improvements nor a waiver of any of HECO’s rights;

(e) Evidence of insurance coverages increased if appropriate to cover the full replacement value of the Facility following completion of the Increment Two Capacity Upgrade in the form and types of coverage for insurance policies required under the Power Purchase Agreement; and

(f) Evidence that construction of the Increment Two Capacity Upgrade is complete and that the Acceptance Test described in Section 4E of this Increment Two Capacity Agreement has been satisfactorily accomplished, and a letter from Kalaeloa stating that the Facility as modified by the Increment Two Capacity Upgrade is ready to begin producing electric energy on a commercial basis under the terms and conditions of the Power Purchase Agreement as amended and otherwise modified by this Increment Two Capacity Agreement.

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B. Increment Two Capacity In-Service Date Condition Precedent.

Notwithstanding any other provisions of this Increment Two Capacity Agreement, HECO’s obligations under this Increment Two Capacity Agreement to purchase power delivered by Kalaeloa by virtue of the Increment Two Capacity and to pay the portion of the Capacity Charge corresponding to the Increment Two Capacity, and any and all obligations of HECO that are ancillary to that purchase and that payment, are all contingent upon (1) the effectiveness of all terms of the Increment One Capacity Agreement and (2) the occurrence of the Increment Two Capacity In-Service Date.

4. Design, Construction and Testing of Increment Two Capacity Upgrade.

A. General.

Except as otherwise provided in this Increment Two Capacity Agreement, Kalaeloa or its contractors shall furnish all financial resources, labor, tools, materials, equipment, transportation, supervision and other goods and services necessary to completely design and construct the Increment Two Capacity Upgrade. The design and construction of the Increment Two Capacity Upgrade shall take place using Good Engineering and Operating Practices.

B. Permits and License.

Kalaeloa shall be responsible for the acquisition of all permits and licenses, and the completion of all environmental review procedures, required for the construction of the Increment Two Capacity Upgrade and operation of the Facility following completion of the Increment Two Capacity Upgrade.

C. [Reserved.]

D. Status Reports.

At HECO’s request, Kalaeloa shall provide opportunities for HECO to meet with appropriate personnel of Kalaeloa or its contractors to discuss and assess the status of permitting, environmental review procedures, design, construction and operation of the Increment Two Capacity Upgrade.

E. Acceptance Testing and Timing.

Immediately following the completion of the Increment Two Capacity Upgrade, HECO and Kalaeloa shall conduct the Acceptance Test. Kalaeloa shall use commercially reasonable efforts to cause the Facility as modified by the Increment Two Capacity Upgrade to satisfy the Acceptance Test no later than one hundred (100) days after the commencement of the next upcoming “C” Inspection for Combustion Turbine No. 2, or such later date as to which Kalaeloa and HECO may agree by a subsequent written agreement. If the Acceptance Test is not satisfactorily completed by said deadline due solely to delay caused by HECO, then said deadline shall be extended for the time necessary to accommodate the delay to the extent caused by HECO. If the Acceptance Test is not satisfactorily completed by said deadline, then each of Kalaeloa and HECO shall have the option to declare this Increment Two Capacity Agreement

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null and void, which declaration shall be in writing and shall be delivered to the other party within sixty days after said deadline (as may have been extended pursuant to this paragraph) or such longer time as HECO and Kalaeloa may agree by a subsequent written agreement.

F. Regarding M Upgrade

(1) Kalaeloa caused to be installed the modifications to the first combustion turbine as part of the M Upgrade during the “C” Inspection that commenced on May 2, 2004. Kalaeloa hereby notifies HECO that said modifications to the first combustion turbine have been completed and accepted by Kalaeloa. Kalaeloa has instructed Alstom Power Inc. to proceed with the modifications to the second combustion turbine to complete the M Upgrade during the next upcoming “C” Inspection for Combustion Turbine No. 2, and Kalaeloa shall notify HECO in writing by July 29, 2005 (or such later date as to which Kalaeloa and HECO may agree by a subsequent written agreement) whether the entire M Upgrade has been completed and accepted by Kalaeloa. If Alstom Power Inc. has not completed and Kalaeloa has not accepted the entire M Upgrade by said deadline, then HECO and Kalaeloa shall each have the option to declare this Increment Two Capacity Agreement null and void, which declaration shall be delivered to the other party within sixty days after said deadline (as may have been extended pursuant to this paragraph) or such longer time as Kalaeloa and HECO may agree by a subsequent written agreement.

(2) In the event Kalaeloa requires HECO to purchase the Facility pursuant to Section 3.3H of the Power Purchase Agreement, the parties agree that the phrase “original equity investment” does not include any expenses related to the M Upgrade. Kalaeloa has delivered to HECO that certain letter dated June 30, 2004, a copy of which is attached hereto as Exhibit 4, setting forth calculations of (i) the purchase price for the Facility for purposes of said Section 3.3H, which calculation does not include any expenses related to the M Upgrade, and (ii) the fair market value of the Facility for purposes of said Section 7.2B(1), similar in format to the letters from Kalaeloa to HECO dated March 31, 2000 and April 4, 1997.

G. Voltage Monitoring Equipment at Points of Interconnection

Kalaeloa shall reimburse HECO for the cost to purchase and install a model 7100S Power Quality Monitor manufactured by Drantez-BMI (or an equivalent power quality monitor acceptable to the parties) at the Points of Interconnection or as close as practicable thereto (which shall be deemed to be HECO’s Kalaeloa 138 kV Substation) at the 138 kV level to measure the parameters necessary to determine whether a fault condition as described in Section 1.109 of the Power Purchase Agreement has occurred and the magnitude thereof. The cost to be reimbursed by Kalaeloa to HECO for the purchase and installation of such equipment shall not exceed $15,000. Kalaeloa shall pay to HECO $7,500 of this sum within sixty (60) days of the execution of the Increment Two Capacity Agreement with the balance due within thirty (30) days of HECO’s invoice for same following completion of the installation. HECO shall operate and maintain such equipment at its own expense.

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5. Payment for Adjustments to Interconnection Facilities.

Based upon Kalaeloa’s representations below, HECO has determined that no upgrades to the electrical transmission facilities between HECO’s CEIP Substation and the Points of Interconnection are necessary or advisable as a result of the Increment Two Capacity, as further described in the Interconnection Requirement Study For Kalaeloa Partners, L.P.’s Proposed 235 MW (Net) Combined-Cycle Operating Facility Connected to the HECO Transmission System at Kalaeloa dated September 2004. HECO has determined that certain relay settings must be changed, and Kalaeloa shall reimburse HECO for the actual cost thereof within thirty (30) days after completion thereof and presentation by HECO to Kalaeloa of invoices or other documentation demonstrating such actual cost; provided, however, that if the amount to be reimbursed by Kalaeloa to HECO for the cost of the foregoing exceeds $20,000, then Kalaeloa may notify HECO by writing received by HECO within the time stated for payment of the reimbursement that Kalaeloa elects to terminate this Increment Two Capacity Agreement, whereupon HECO shall not be required to accept or pay for the Increment Two Capacity. HECO may, at its option, collect the cost of the foregoing through an offset in the payment of the Monthly Invoice not to exceed the portion of the Capacity Charge corresponding to the New Capacity payable under such Monthly Invoice. The aforesaid Interconnection Requirement Study was performed on the basis of the following representations made by KPLP to HECO: (i) the M Upgrade involves only changes to the Facility’s combustion turbines and no changes to the Facility’s electrical equipment (such as its three generators) and (ii) the Facility’s single-line diagrams and protective relay list will remain the same as those attached to the Power Purchase Agreement. In reliance upon the foregoing representations, HECO has not reviewed the single-line diagram and protective relays of the Facility.

6. Rates for Purchase.

Subject to the other provisions of the Power Purchase Agreement, HECO shall, from and after the Increment Two Capacity In-Service Date, accept and pay for Net Electrical Energy Output by the Facility and delivered to the Points of Interconnection and make Capacity Payments to Kalaeloa, as set forth in the Power Purchase Agreement as modified by this Section 6. The respective rights and obligations accrued by HECO and Kalaeloa with respect to the payment and receipt of Energy Charges and Capacity Charges for the period prior to the Increment Two Capacity In-Service Date shall continue to be governed by the provisions of the Power Purchase Agreement without giving effect to the amendments and other modifications set forth in this Section 6.

A. Regarding Section 5.1 of the Power Purchase Agreement.

HECO’s obligation to pay the Energy Charge shall remain as set forth in Section 4A (captioned “Regarding Section 5.1 of the Power Purchase Agreement”) of the Increment One Capacity Agreement.

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B. Regarding Section 5.2A(2) of the Power Purchase Agreement.

Effective upon the Increment Two Capacity In-Service Date, the provisions in Section 5.2A(2) of the Power Purchase Agreement are deleted and of no further force or effect and replaced with the word “[Reserved]”.

C. Regarding Section 5.2A(3) of the Power Purchase Agreement.

Section 5.2A(3) is amended in its entirety to read as follows:

(3) Liquidated Damages Due to Failure to Achieve On-peak EFOR Requirements

(a) As a material inducement to HECO’s decision to enter into the Increment Two Capacity Agreement, Kalaeloa represents, warrants and guarantees to HECO that, from and after the Increment Two In-Service Date, On-peak EFOR will not exceed six percent (6%) during any Contract Year.

(b) Commencing with the first Contract Year after the Increment Two Capacity In-Service Date, HECO shall calculate the On-peak EFOR for each Contract Year. If the On-peak EFOR is two percent (2%) or less, there will be no reduction from the amount incurred by HECO for the Annual New Capacity Charge for such Contract Year. If the aforesaid calculation demonstrates an On-peak EFOR for such Calendar Year in excess of two percent (2%), for each one-tenth of a percentage point that the On-peak EFOR exceeds two percent (2%) up to a maximum of twelve percent (12%) when rounded to the nearest one-tenth of a percent (0.1%), the amounts incurred by HECO for the Annual New Capacity Charge for such Contract Year shall be reduced by the following amounts:

On-peak EFOR	Amount of Reduction
2.1% to 6.0%	$5,000 per 0.1% in excess of 2.0%
6.1% to 12.0%	$10,000 per 0.1% in excess of 6.0%
Greater than 12.0%	No further reduction

7. Calculation of On-peak EFOR.

Effective upon the Increment Two Capacity In-Service Date, Article XXV of the Power Purchase Agreement is amended by adding new Sections 25.5 through 25.8 as follows:

25.5 When neither of the Facility’s combustion turbines is in a reserve shutdown status, the Facility must be able to deliver Net Electrical Energy Output equal to at least the Full Upgraded Capacity (or such other Net Electrical Energy Output as is associated with the capacity as may result from Delay Degradation), when called for by HECO Dispatch, in order to avoid a derating for purposes of calculating On-peak EFOR. If, when called for by HECO Dispatch during periods when neither of the Facility’s combustion turbines is in reserve shutdown status, Kalaeloa is unable to deliver Net

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Electrical Energy Output equal to at least the lesser of the Full Upgraded Capacity or the capacity actually called for by HECO Dispatch, a derate will be assessed equal in magnitude to the Full Upgraded Capacity minus the revenue meter reading (both expressed in terms of kilowatts), for purposes of calculating On-peak EFOR.

25.6 On those occasions when one of the Facility’s combustion turbines is in a reserve shutdown status, the Facility must be able to deliver Net Electrical Energy Output equal to at least the Prorated Shutdown Capacity (or such other Net Electrical Energy Output as is associated with the capacity as may result from Delay Degradation), when called for by HECO Dispatch, in order to avoid a derating for purposes of calculating On-peak EFOR. If, when called for by HECO Dispatch during periods when one of the Facility’s combustion turbines is in a reserve shutdown status, Kalaeloa is unable to deliver Net Electrical Energy Output equal to at least the lesser of the Prorated Shutdown Capacity or the capacity actually called for by HECO Dispatch, a derate will be assessed equal in magnitude to Prorated Shutdown Capacity, minus the revenue meter reading (both expressed in terms of kilowatts), for purposes of calculating On-peak EFOR.

25.7 Under this Agreement, the ratio for On-peak EFOR is to be calculated in accordance with North American Electric Reliability Council (NERC) Generating Availability Data System (GADS) formulas, excluding the applicable seasonal adjustment. As a result, Net Dependable Capacity (“NDC”) and Net Maximum Capacity (“NMC”) are used in calculating Equivalent Planned Derated Hours and Equivalent Unplanned Derated Hours. In all cases, regardless of ambient conditions and degradation (except for Delay Degradation), NDC and NMC will continue to be Full Upgraded Capacity. Deratings that are less than or equal to 2% of the NMC, and/or less than or equal to 30 minutes in duration, will continue to be included as deratings in determining Derated Hours.

25.8 For purposes of calculating On-peak EFOR, the routine maintenance requirements provided in Section 3.2D(7) for any “C” Inspection commenced after the Increment Two In-Service Date shall be thirty-five (35) days per combustion turbine, or such longer time as agreed by HECO in writing prior to commencement of such “C” inspection, instead of fifty (50) days. The time allotted for the steam turbine maintenance portion of the “C” Inspection shall remain unchanged.

8. Limitation on Certain Reductions in and Deductions from Capacity Payments and on Liquidated Damages.

Effective upon the Increment Two Capacity In-Service Date, Article XXVI of the Power Purchase Agreement is amended in its entirety to read as follows:

ARTICLE XXVI

LIMITATION ON CERTAIN REDUCTIONS IN AND DEDUCTIONS FROM

CAPACITY PAYMENTS AND ON LIQUIDATED DAMAGES

26.1 Any other provision of this Agreement to the contrary notwithstanding, for each Contract Year, the sum of the following items shall not be assessed or accrue to the

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extent such sum exceeds the Annual New Capacity Charge for such Contract Year: the reduction in the Capacity Charge corresponding to the New Capacity pursuant to Section 5.2A(3) and the Increment Two Capacity pursuant to Section 5.2A(4), liquidated damages payable under Article XXIV, the deduction from the Capacity Charge for New Capacity pursuant to Section 27.2.5, and liquidated damages payable under Article XXVII; and HECO acknowledges that it shall not seek any further remedies against Kalaeloa related to such failures, except in cases of willful misconduct or in cases in which HECO may have a claim to equitable relief.

26.2 If any amounts owed by Kalaeloa for the reduction in the Capacity Charge corresponding to the New Capacity pursuant to Section 5.2A(3) and the Increment Two Capacity pursuant to Section 5.2A(4), the deduction from the Capacity Charge corresponding to the New Capacity pursuant to Section 27.2.5, liquidated damages payable under Article XXVII or reimbursement of the cost of the Interconnection Addition is not paid when due, HECO shall have the right to set off any payment due against HECO’s payments of subsequent Monthly Invoices as necessary, provided, however, that the maximum amount set off against any one Monthly Invoice shall be limited to the portion of the Capacity Charge corresponding to the New Capacity payable that month.

9. Reliability Standards and Liquidated Damages.

Effective upon the Increment Two Capacity In-Service Date, the following is added to the Power Purchase Agreement as a new Article XXVII:

ARTICLE XXVII

RELIABILITY STANDARDS AND LIQUIDATED DAMAGES

27.1 Relationship Between Articles VIII, XXIV and XXV of Power Purchase Agreement.

The liquidated damages set forth in Article VIII of this Agreement were agreed to in the context of a Facility able to deliver 180,000 KW capacity pursuant to HECO Dispatch, and the parties agree that such liquidated damages continue to be an appropriate remedy for HECO and liability for Kalaeloa with respect to such capacity. However, in light of the addition to the Facility of the New Capacity, HECO and Kalaeloa agree that, from and after the Increment Two Capacity In-Service Date, an additional remedy for HECO and additional liability for Kalaeloa are appropriate and that the provisions of this Article XXVII shall have effect from and after the Increment Two Capacity In-Service Date. The respective rights and obligations accrued by HECO and Kalaeloa with respect to liquidated damages under Article VIII of this Agreement for the period prior to the Increment Two Capacity In-Service Date shall continue to be governed by the provisions of this Agreement without giving effect to the provisions of this Article XXVII. Article XXIV of this Agreement is intended to address circumstances other than the unavailability of capacity addressed under Articles VIII and XXV, and the respective rights and obligations of HECO and Kalaeloa under said Article

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XXIV are separate from and in addition to the respective rights and obligations of HECO and Kalaeloa under said Articles VIII and XXV.

27.2 Full Plant Trips.

27.2.1 As a material inducement to HECO’s decision to enter into this Increment Two Capacity Agreement, Kalaeloa represents, warrants and guarantees to HECO that, from and after the Increment Two Capacity In-Service Date, during any twelve (12) month period, there will be no more than one Full Plant Trip that could have been avoided through the employment of Good Engineering and Operating Practices. Kalaeloa’s failure to comply with the foregoing shall not be considered a default under Section 7.1A; provided, however, that nothing in this sentence shall be interpreted as precluding the inclusion of Full Plant Trips (1) for purposes of calculating the Equivalent Availability Factor and Equivalent Forced Outrage Rate referenced in clause (a) of Section 7.1A(4) and (2) within the Unit Trips referenced in clause (b) of Section 7.1A(4) as and to the extent any such Full Plant Trips also constitute one or more Unit Trips.

27.2.2 For each Full Plant Trip (Category I), Kalaeloa shall pay to HECO as liquidated damages the sum of ONE HUNDRED THOUSAND DOLLARS ($100,000).

27.2.3 For each Full Plant Trip (Category II), Kalaeloa shall pay to HECO as liquidated damages the sum of FIFTY THOUSAND DOLLARS ($50,000).

27.2.4 Kalaeloa shall earn a grace period to be used in determining whether an event is a Full Plant Trip (Category I) or Full Plant Trip (Category II) by providing HECO’s Load Dispatcher, prior to the Unplanned Removal From Service of the first generator to be so removed, with notice that the Facility is likely to experience a Full Plant Trip. In order to qualify as a notice of the type referred to in the preceding sentence, the notice must (a) be made in a direct and two-way communication between Kalaeloa or its operator’s personnel and HECO’s Load Dispatcher through such media as the “hot line” between the Facility’s control room and that of HECO’s Load Dispatcher, (b) clearly and specifically state that there is likely to be an Unplanned Removal From Service of the two combustion turbines at the Facility and (c) be acknowledged by HECO’s Load Dispatcher as conveying the message that there is likely to be an Unplanned Removal From Service of the two combustion turbines at the Facility. If Kalaeloa provides notice which satisfies the requirements set forth in the first two sentences of this Section 27.2.4, the number of minutes that elapse between the receipt of such notice by HECO’s Load Dispatcher and the actual Unplanned Removal From Service of the Facility’s first combustion turbine (the “grace period”) shall, for purposes of determining whether the event in question is to be classified as a Full Plant Trip (Category I) or Full Plant Trip (Category II) for purposes of assessing the liquidated damages set forth in Section 27.2.2 or 27.2.3, be added to the number of minutes that actually elapsed between the Unplanned Removal From Service of the first combustion turbine and the Unplanned Removal From Service of the second combustion turbine.

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27.2.5 If three or more Full Plant Trip (Category I) events occur during any twelve (12) month period (regardless of whether or not, by virtue of the grace period provided under Section 27.2.4, such events were treated as Full Plant Trip (Category I) events for purposes of assessing liquidated damages), the occurrence of the third Full Plant Trip (Category I) event within such twelve (12) month period shall result in a twenty-five percent (25%) deduction from the amount payable as Capacity Charge for New Capacity for the period commencing with the date of such third Full Plant Trip (Category I) event until such time as Kalaeloa has adequately addressed, to HECO’s satisfaction in HECO’s sole but non-arbitrary discretion, the circumstances giving rise to the Full Plant Trip problem, as evidenced by HECO’s written notice to Kalaeloa to that effect. If Kalaeloa is not satisfied with the exercise of HECO’s sole discretion in determining whether Kalaeloa has adequately addressed such circumstances or HECO is not reasonably prompt in responding to Kalaeloa, Kalaeloa may, at its own expense, submit the issue of whether or not Kalaeloa has addressed the circumstances giving rise to the Full Plant Trip problem to an independent engineer from the list of qualified engineers maintained pursuant to Section 3.F(6) (the “Section 3.F(6) List”). If Kalaeloa decides to submit such issue to the assessment of an independent engineer, Kalaeloa shall provide HECO with written notice to that effect. If HECO and Kalaeloa do not agree within seven (7) days of the date of HECO’s receipt of the aforesaid notice from Kalaeloa upon the independent engineer from the Section 3.F(6) List to be retained by Kalaeloa for such purpose, Kalaeloa shall designate the independent engineer from the Section 3.F(6) List and the assessment of such independent engineer shall be binding on the parties. If such independent engineer determines that Kalaeloa has adequately addressed the problem, such engineer shall also decide the date upon which Kalaeloa achieved this result so that the parties will know that date from which the aforesaid twenty-five percent (25%) deduction from the portion of the Capacity Charge corresponding to the New Capacity ceased to apply. The provisions of Article XIV shall not apply to the selection of the independent engineer under this Section 27.2.5 or the conduct of the engineering assessment under this Section 27.2.5.

27.2.6 The twenty-five percent (25%) deduction from the portion of the amount payable as Capacity Charge corresponding to the New Capacity pursuant to the provisions of Section 27.2.5 is intended to correlate to the portion of the amount payable as Capacity Charge corresponding to the New Capacity to take into account the unreliability of such New Capacity as evidenced by the occurrence of Full Plant Trip (Category I) events and is not intended to compensate HECO for the Full Plant Trip events themselves. Accordingly, liquidated damages shall still be payable as provided in Sections 27.2.2 through 27.2.4 for all Full Plant Trip (Category I) and/or Full Plant Trip (Category II) events that occur during a period for which there has been a deduction from the Capacity Charge for New Capacity pursuant to Section 27.2.5.

27.3 Payment to HECO.

Payment of liquidated damages to HECO under this Article XXVII is due thirty (30) days after written demand therefor from HECO.

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10. Other Clarifications, Modification and Amendments to the Power Purchase Agreement.

Effective upon the Increment Two Capacity In-Service Date, the following provisions of the Power Purchase Agreement are deemed to be clarified, modified or amended as set forth in this Section 10:

A. Regarding Section 3.1A of the Power Purchase Agreement.

The words “and Increment Two Capacity” are inserted after the words “Firm Capacity” in the second line of Section 3.1A.

B. Regarding Sections 23.18 and 23.19 of the Power Purchase Agreement.

Sections 23.18 and 23.19 of the Power Purchase Agreement are amended in their entirety to read as follows:

23.18 Steam Sales Contract Monthly Report

Not more than 30 days following the end of each Calendar Month, Kalaeloa shall provide HECO with a written report setting forth for each one-hour interval during each On-peak Period during such Calendar Month the amount of process steam exported by the Facility pursuant to the Steam Sales Contract and the average (the “On-peak Monthly Steam Average”) export of process steam for all such one-hour intervals during the month (the “Steam Sales Monthly Report”). If any Steam Sales Monthly Report indicates that the On-peak Monthly Steam Average exceeds 110,000 lb/hour that month, then the Steam Sales Monthly Report shall also include an explanation of the reasons for the On-peak Monthly Steam Average exceeding 110,000 lb/hour and a projection for the Calendar Year of the amount of process steam to be exported by the Facility pursuant to the Steam Sales Contract. If any such yearly projection indicates that the On-peak Monthly Steam Average is projected to exceed 110,000 lb/hour in a Month remaining in such Calendar Year, then the Steam Sales Monthly Report shall also include an explanation of the reasons therefor.

23.19 Additional Covenant Concerning Steam Sales Contract

If any Steam Sales Monthly Report indicates that the counterparty to the Steam Sales Contract has increased its take of process steam from the Facility beyond the equivalent of 110,000 lb/hour during any On-peak Period resulting in or contributing to a derating of the Facility’s capability below the Full Upgraded Capacity (as such may be reduced by any Delay Degradation), or that said counterparty is projected to increase its take of process steam from the Facility beyond the equivalent of 110,000 lb/hour during the Calendar Year such that the increased take of steam may result in deratings of the Facility’s capability below the Full Upgraded Capacity (as such may be reduced by any Delay Degradation) during On-peak Periods, then Kalaeloa shall promptly take such actions as it determines to be appropriate to eliminate the occurrence of such

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deratings below the Full Upgraded Capacity (as such may be reduced by any Delay Degradation) and shall report to HECO on its efforts to eliminate the occurrence of such deratings below the Full Upgraded Capacity (as such may be reduced by any Delay Degradation).

In the event the counterparty’s take of process steam from the Facility beyond the equivalent of 110,000 lb/hour during the Calendar Year results in or contributing to deratings below the Full Upgraded Capacity (as such may be reduced by any Delay Degradation) during more than thirty (30) On-peak Periods during that Calendar Year, Kalaeloa shall employ all commercially reasonable efforts to eliminate such process steam-related deratings below the Full Upgraded Capacity (as such may be reduced by any Delay Degradation) or to induce such counterparty to limit its take of process steam from the Facility to the equivalent of 110,000 lb/hour during On-peak Periods, provided that Kalaeloa is not required to induce any limitation that would have the effect of causing the Facility to fail to achieve the Minimum Thermal Threshold or remain a Qualifying Facility.

C. Regarding Attachment G of the Power Purchase Agreement.

Attachment G to the Power Purchase Agreement is deemed replaced in its entirety by Attachment G to this Increment Two Capacity Agreement.

D. Regarding Attachment R of the Power Purchase Agreement.

Attachment R to the Power Purchase Agreement is deemed replaced in its entirety by Attachment R to this Increment Two Capacity Agreement.

E. Regarding Attachment W of the Power Purchase Agreement.

Attachment W to the Power Purchase Agreement is deemed replaced in its entirety by Attachment W to this Increment Two Capacity Agreement.

F. Regarding Attachment D of the Power Purchase Agreement.

No modifications to Attachment D to the Power Purchase Agreement are required as a result of the Increment Two Capacity Upgrade, and said Attachment D remains applicable to the Facility as modified by the Increment Two Capacity Upgrade.

11. Other Terms Unchanged.

All of the terms and conditions of the Power Purchase Agreement that are not altered, amended or replaced by the provisions of this Increment Two Capacity Agreement shall remain in full force and effect. In the event that a conflict arises between the Power Purchase Agreement and this Increment Two Capacity Agreement, this Increment Two Capacity Agreement shall prevail, but the respective documents shall be interpreted to be in harmony with each other where possible.

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12. Kalaeloa’s Representations, Warranties and Guarantees of Performance With Respect to New Capacity.

A. As a material inducement to HECO’s decision to enter into this Increment Two Capacity Agreement, Kalaeloa represents to HECO that once the Increment Two Capacity Upgrade is complete, Kalaeloa expects that the annual average of its export of process steam under the Steam Sales Contract will be equivalent to approximately 110,000 lb/hour and that Kalaeloa has no information indicating that the counterparty to the Steam Sales Contract will increase its annual take of process steam beyond this expected average.

B. As a material inducement to HECO’s decision to enter into this Increment Two Capacity Agreement, Kalaeloa represents, warrants and guarantees to HECO that, from and after the Increment Two Capacity In-Service Date, the Facility will, during each Calendar Year, achieve the Minimum Thermal Threshold, and, as HECO’s sole remedy therefor, except in cases of willful misconduct or cases in which HECO has a claim for equitable relief, Kalaeloa shall pay liquidated damages as set forth in Article XXIV of the Power Purchase Agreement.

C. Without limitation to the effect of Sections 12.A. and 12.B. above, Kalaeloa, as a material inducement to HECO’s decision to enter into this Increment Two Capacity Agreement, represents, warrants and guarantees to HECO that, from and after the Increment Two In-Service Date, the Facility will have and maintain the capability to produce and deliver the Baseline Capacity and the New Capacity to the extent required by the Power Purchase Agreement, as amended and clarified by the Increment Two Capacity Agreement and the previous amendments and clarifications of the Power Purchase Agreement identified in Recital “A” to the Increment Two Capacity Agreement, to the Metering Point under HECO Dispatch.

D. As a material inducement to HECO’s decision to enter into this Increment Two Capacity Agreement, Kalaeloa reaffirms its representations and warranties given in the Consent and Agreement between the parties dated December 31, 2003 and further represents, warrants and guarantees to HECO that Kalaeloa can complete the Increment Two Capacity Upgrade and implement this Increment Two Capacity Agreement without the necessity for modifications to (i) the back-up fuel supply agreement referred to in Section 3.2G of the Power Purchase Agreement or (ii) any obligations or commitments that HECO may have regarding potable or cooling water. Kalaeloa represents, warrants and guarantees to HECO that, in the event Kalaeloa is unable to obtain fuel from its primary supplier, Kalaeloa shall make a good faith effort to acquire alternative supplies of low sulfur residual fuel oil as primary fuel and diesel oil as start-up and shutdown fuel necessary to operate the Facility before calling upon HECO to fulfill HECO’s obligation to provide fuel to Kalaeloa. Kalaeloa agrees and acknowledges that any obligations or commitments that HECO may have regarding potable or cooling water are limited to supplies of potable water and cooling water in quantities reasonably adequate to permit operation of the Facility in the manner provided for in the Power Purchase Agreement prior to the commencement of the Increment Two Capacity Upgrade.

13. Regulatory Approval.

A. The parties shall use good faith efforts to obtain, as soon as practicable, a final non-appealable order from the Public Utilities Commission that does not contain terms and

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conditions deemed to be unacceptable to HECO, and is in a form deemed to be reasonable by HECO, in its sole, but nonarbitrary, discretion, approving this Increment Two Capacity Agreement and ordering that:

(1) the purchase power costs to be incurred by HECO as a result of this Increment Two Capacity Agreement are reasonable;

(2) HECO’s purchase power arrangements under this Increment Two Capacity Agreement, pursuant to which HECO will purchase Increment Two Capacity from Kalaeloa and may purchase additional energy, are prudent and in the public interest;

(3) the Fuel Component and the Additive Component of the purchased energy costs and related revenue taxes to be incurred by HECO pursuant to this Increment Two Capacity Agreement may be included in HECO’s energy cost adjustment clause to the extent such costs are not included in base rates; and

(4) HECO may include the costs of the Increment Two Capacity and the purchased power incurred by HECO pursuant to this Increment Two Capacity Agreement in its revenue requirements for ratemaking purposes and for the purposes of determining the reasonableness of HECO’s rates.

B. Notwithstanding any other provisions of this Increment Two Capacity Agreement to the contrary, HECO’s obligations under this Increment Two Capacity Agreement to purchase power delivered by Kalaeloa by virtue of the Increment Two Capacity and to pay the Capacity Charge for the Increment Two Capacity, and any and all obligations of HECO which are ancillary to that purchase and that payment, are all contingent upon obtaining the order described in this Section 13. (Such order is referred to hereinbelow as the “PUC Approval Order”.)

C. As used in Section 13.A. above, the term “final non-appealable order from the Public Utilities Commission” means a PUC Approval Order (a) that is considered to be final by HECO, in its sole discretion, because HECO is satisfied that no party to the subject Public Utilities Commission proceeding intends to seek a change in such PUC Approval Order through motion or appeal, or (b) that is not subject to appeal to any Circuit Court of the State of Hawaii or the Supreme Court of the State of Hawaii, because the thirty (30) day period permitted for such an appeal has passed without the filing of notice of such an appeal, or (c) that was affirmed on appeal to any Circuit Court of the State of Hawaii or the Supreme Court, or the Intermediate Appellate Court upon assignment by the Supreme Court, of the State of Hawaii, or was affirmed upon further appeal or appellate process, and that is not subject to further appeal, because the jurisdictional time permitted for such an appeal (and/or further appellate process such as a motion for reconsideration or an application for writ of certiorari) has passed without the filing of notice of such an appeal (or the filing for further appellate process). Promptly after the issuance of a PUC Approval Order, HECO shall provide Kalaeloa with a copy of such PUC Approval Order together with a written statement as to whether the conditions set forth in (i) Section 11A and (ii) clause (a) of this Section 13C have been satisfied.

D. As used in this Increment Two Capacity Agreement, the term “PUC Approval Date” shall be defined as (a) the date of issuance of the PUC Approval Order if HECO provides

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the written statement referred to in the last sentence of Section 13C to the effect that the condition referred to in clause (a) of Section 13C of this Increment Two Capacity Agreement has been satisfied or (b) as follows:

(1) If a PUC Approval Order is issued and is not made subject to a motion for reconsideration filed with the Public Utilities Commission or an appeal, the PUC Approval Date shall be the date one day after the expiration of the thirty-day period permitted for filing of an appeal following the issuance of the PUC Approval Order.

(2) If the PUC Approval Order became subject to a motion for reconsideration, and the motion for reconsideration is denied or the PUC Approval Order is affirmed after reconsideration, and such order is not made subject to an appeal, the PUC Approval Date shall be deemed to be the date one day after the expiration of the thirty-day period permitted for filing of an appeal following the order denying reconsideration of or affirming the PUC Approval Order.

(3) If the PUC Approval Order, or an order denying reconsideration of the PUC Approval Order or affirming approval of the PUC Approval Order after reconsideration, becomes subject to an appeal, then the PUC Approval Date shall be the date upon which the PUC Approval Order becomes a non-appealable order within the meaning of Section 13.C.

14. Entire Agreement.

This Increment Two Capacity Agreement and the Power Purchase Agreement, as amended herein, embody the whole agreement and understanding of the parties as to matters described herein and supersede and nullify all prior agreements, arrangements and understandings related to the subject matter of this Increment Two Capacity Agreement; provided, however, that nothing in this Section 14 shall cause the Power Purchase Agreement to be invalid or unenforceable against HECO or Kalaeloa on the basis of regulatory action concerning this Increment Two Capacity Agreement.

15. Effective Date.

Provided the conditions precedent to the effectiveness of Section 2 and Sections 6 through 11 of this Increment Two Capacity Agreement as set forth in the next sentence of this Section 15 have been satisfied, Section 2 and Sections 6 through 11 hereof shall become effective on the Increment Two Capacity In-Service Date. The conditions precedent referenced in the first sentence of this Section 15 are (a) the occurrence of the PUC Approval Date as defined in Section 13 above, (b) the consent to this Increment Two Capacity Agreement of ING Capital LLC, as Agent for the “Lenders” under the Amended and Restated Loan and Note Purchase Agreement, dated as of December 10, 1991 (the “Lender Approval”), (c) the acceptance of the M Upgrade by Kalaeloa and (d) the satisfactory completion of the Acceptance Test. Kalaeloa shall use good faith efforts to obtain Lender Approval. Should the PUC Approval Date not occur by August 1, 2005, or such later date as to which HECO and Kalaeloa may agree by a subsequent written agreement, or should the Lender Approval not be obtained within a reasonable period (expected to be approximately sixty (60)) days after the full execution of this Increment Two Capacity Agreement and the delivery hereof to the Agent (which Kalaeloa

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agrees to cause to be done promptly after full execution by the parties), but in no event later than January 3, 2005, Section 2 and Sections 6 through 11 of this Increment Two Capacity Agreement shall be null and void ab initio, and HECO and Kalaeloa shall be free of all obligations under said Section 2 and Sections 6 through 11 and shall pursue no remedies against one another arising out of or related to said Section 2 and Sections 6 through 11.

16. Miscellaneous.

A. The failure of either party to enforce at any time any of the provisions of this Increment Two Capacity Agreement, or to require at any time performance by the other party of any of the provisions hereof, shall in no way be construed to be a waiver of such provisions, nor in any way to affect the validity of this Increment Two Capacity Agreement or any part hereof, or the right of such party to enforce every such provision.

B. No modification or waiver of all or any part of this Increment Two Capacity Agreement shall be valid unless it is reduced to writing which expressly states that the parties thereby agree to a waiver or modification as applicable and signed by both parties.

C. This Increment Two Capacity Agreement may be executed in several counterparts and all so executed counterparts shall constitute one agreement, binding on both parties hereto, notwithstanding that both parties may not be signatories to the original or the same counterpart.

D. This Increment Two Capacity Agreement and all documents executed and delivered in connection herewith, and all notices and other communications given pursuant to this Increment Two Capacity Agreement, may be executed and signatures transmitted electronically via the Internet or facsimile.

IN WITNESS WHEREOF, the parties have executed this Increment Two Capacity Agreement by their respective duly-authorized officers as of the date first stated above.

HAWAIIAN ELECTRIC COMPANY, INC.		KALAELOA PARTNERS, L.P.
By	/s/ Thomas C. Simmons	By	PSEG Kalaeloa Inc., Its general partner
	Its Vice President – Power Supply
By	/s/ Thomas L. Joaquin	By	/s/ Royal Daniel
	Its SVP – Operations		Its Vice President
Executed on: October 12, 2004		Executed on: October 12, 2004

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EXHIBITS
EXHIBIT 1	Letter dated July 29, 2004, regarding LSFO forwarding pumps
EXHIBIT 2	Letter dated October 8, 2004, regarding ground system and lightening protection
EXHIBIT 3	Capacity Evaluation Protocol Kalaeloa Cogeneration Facility Post M Upgrade Case for up to 209 MW for Two CT/Case for One CT Operation identified as “9/23/04”.
EXHIBIT 4	Letter dated June 30, 2004, setting forth calculations of (i) the purchase price for the Facility for purposes of Section 3.3H and (ii) the fair market value of the Facility for purposes of Section 7.2B(1)

ATTACHMENTS
ATTACHMENT G	(see 10.C.)
ATTACHMENT R	(see 10.D.)
ATTACHMENT W	(see 10.E.)

EXHIBIT 1

July 29, 2004

Hawaiian Electric Company, Inc.

PO Box 2750

Honolulu, Hawaii 96840-0001

Attention:	Ward D. Saunders, P.E.
	Power Purchase Contracts Administrator
Subject:	Plant Reliability Improvements
Ref.	Under Voltage Study Results

Dear Ward,

In accordance with the above referenced study, we will be replacing the variable frequency drives presently installed on all three LSFO forwarding pumps.

The new variable frequency drives with improved fault recovery and disturbance ride through capability are of the Baldor series 15 H or similar type and will be installed during the next upcoming full plant outage which is planned for April of 2005.

Though numerous modifications to the existing drives/pump controls improved the supply voltage disturbance ride through capabilities, it is unclear as to what magnitude and duration can be withstood. However the Facility has survived most of the faults after the implementation of these improvements.

The new drives as proposed have a clearly defined disturbance ride-through capability of the absence of voltage for a duration of up to 2 seconds, thus equipment’s and plant reliability will be further increased. Experience at the Facility has shown that disturbances seldom, if ever, drop the supply voltage to zero volts for a duration of more than 1 second.

Best Regards.

/s/ H.R. Tobler

H.R. Tobler

General Manager

Kalaeloa Partners, L.P.

EXHIBIT 2

October 8, 2004

Hawaiian Electric Company, Inc. (“HECO”)

PO Box 2750

Honolulu, Hawaii 96840-0001

Attention:	Ward D. Saunders, P.E.
	Power Purchase Contracts Administrator

Subject: Action Items for Kalaeloa Facility Grounding System and Lightning Protection

Dear Ward,

Kalaeloa Partners, L.P. (“Kalaeloa”) agrees to complete the following action items and implement the applicable procedure changes:

a. Grounding System

i. Replace two defective exothermic weld connections. (completed prior to 8/17/04)

ii. Modify the plant’s maintenance program to include periodic evaluations of the grounding system and visual checks of all accessible exothermic weld connections. (completed prior to 8/17/04)

iii. Test and repair as part of regular preventative maintenance.

b. Electronic Components

i. Identify critical components essential for the operation of the plant in close proximity to the stacks, which are the most probable target iin case of a lightning strike. (completed prior to 8/17/04)

ii. Assure adequate spare parts of such components. (in progress, parts inventory expected to be complete by October 2004)

iii. Provide list of components and planned spare inventory to HECO.

c. Training

i. Train operations and maintenance personnel how to respond quickly in case of problems, i.e., learn how to quickly detect defective

components based on symptoms, learn how to replace defective components without unnecessarily and adversely impacting the safe operation of the plant. (Ongoing process).

d. Study and Implementation

i. Kalaeloa has completed a study by an independent third party that confirmed that the Facility currently meets the design specifications of the Turnkey Design/Build Contract between Kalaeloa and ABB Energy Services, Inc. dated November 8, 1988 with respect to Section 3.8.1 “Station Grounding” and such has been forwarded to you previously.

Though the above mentioned steps will not guarantee that lightning could never cause trips in the future, complete implementation of such steps will greatly reduce the chance that lightning will cause a trip of both CT’s and increase the likelihood that the plant recovery process from a lightning event should be minimized as compared to the January 2004 lightning event.

Kalaeloa will retain an independent third party consultant to review the current state of the Facility in order to determine whether the 1989 Edition of NFPA 78 (the “1989 NFPA 78”) was used as the design and construction basis of the Facility. A copy of such consultant’s report will be provided to HECO. If it is determined by such third party consultant that the Facility’s design and/or construction did not incorporate the material provisions of the 1989 NFPA 78, then, if Kalaeloa does not, within a reasonable time (as such is determined by such independent third party consultant) take such action to rectify any such matters so that the Facility’s construction meets the material requirements of the 1989 NFPA 78, Kalaeloa agrees that upon the expiration of such reasonable time, the Power Purchase Agreement between us and you is hereby clarified so that an “Unplanned Removal From Service” (as defined in the Increment Two Capacity Agreement) caused by fire which results from lightning strikes to the Facility will constitute a “Full Plant Trip” (as defined in the Increment Two Capacity Agreement) until such time as Kalaeloa is in compliance with such material provisions of the 1989 NFPA 78.

Best Regards,

/s/ H.R. Tobler

H.R. Tobler

General Manager

Kalaeloa Partners, L.P.

EXHIBIT 3

Capacity Evaluation Protocol

Kalaeloa Cogeneration Facility

Post M Upgrade

Case for up to 209 MW for Two CT

Case for One CT Operation

Purpose

The purpose of this evaluation protocol is to set forth a protocol to be used to demonstrate the Facility’s ability following implementation of the M Upgrade to provide additional capacity of up to 209 MW, to the Hawaiian Electric Company, Inc. (“HECO”) system and to identify a new level of capacity when the Facility is operating with one combustion turbine (“CT”) and the steam turbine (“ST”) (as measured by HECO’s revenue meters at the Points of Interconnection and with the output corrected to the below agreed upon evaluation conditions which are being used as a proxy to represent reasonable worst case conditions for Facility operations). The results of this evaluation will be used by HECO and Kalaeloa to support current discussions to increase the Firm Capacity.

Capitalized terms used herein and not otherwise defined shall have the meanings ascribed thereto in the Power Purchase Agreement dated as of the 14^th day of October 1988 between KALAELOA Partners, L.P. (“Kalaeloa”) and HECO (as heretofore amended and clarified, the “PPA”).

Test Conditions and Parameters

1. A continuous 48-hour test run of the Facility will be conducted for the case for the full Facility capability, while two shorter 4-hour period runs separate from the 48-hour run will be conducted for the cases of single CT operations (collectively, the “Test”). Any abnormal conditions or equipment failure during any portion of the Test which impact that portion of the Test results shall cause that portion of the Test to end, and in which case the parties after review of the reasons for the Test’s termination shall promptly arrange the scheduling of another Test or portion of a Test by mutual agreement of Kalaeloa and HECO. The 48 hour portion of the Test may be concluded before its 48-hour duration if the determination that enough data has been collected is made jointly by HECO and Kalaeloa. However, each of the two 4-hour one CT operation Test portions should run the entire four hours.

2. For at least one month prior to the Test, turbine washes shall have continued to be conducted on Friday/Saturday and Saturday/Sunday periods respectively.

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3. The commencement of the Test shall be scheduled such that at the conclusion of the Test, the HRSGs will be in their most fouled state in the cleaning cycle and due for wash according to the then current normal wash cycle. The HRSGs shall not be washed during the 48-hour period just prior to the commencement of the Test.

4. The Test timing relative to “C” inspection interval should be the same as the test conducted pursuant to the 189 MW protocol with degradation factors from Attachment D applied as necessary to position the performance of each CT as if it is operating at the following time in the “C” inspection life cycle. The Test shall be corrected as if the Test had been conducted just prior to a “C” inspection being due for at least one of the CTs (i.e. approximately 16,000 operating hours have elapsed since the last C inspection). The other CT should be at the mid point (approximately 8,000 operating hours) following its last “C” inspection. Given the historical and future plans for “C” inspection intervals at one per year and an approximately two year interval between “C” inspections for a given CT this scenario should closely approximate the worst case Facility operating regime relative to operational degradation of the two CTs. The four-hour single CT portion of the Test shall be corrected as if the Test had been conducted just prior to a “C” inspection being due for both of the CTs (i.e. approximately 16,000 operating hours have elapsed since the last C inspection). If the Test is conducted at a time when either CT has not accumulated the operating hours to meet the above criteria, a degradation correction to the Test result will be applied as discussed below.

5. The maximum turbine inlet temperature (“TIT”) setpoint shall be 1854 Deg. F. Actual TIT may vary by no more than a couple degrees from the setpoint due to normal control system variations.

6. The maximum steam injection to fuel ratio (lbs of steam/lb of fuel) shall not exceed 1.5 lbs unless a greater amount is needed to meet the air quality permit requirements of the Facility. Operating conditions shall meet the requirements of all applicable permits.

7. Steam export to Tesoro during the Test shall beat least 110,000 lb/hr or the value thereof necessary for the Facility to achieve PURPA Qualifying Facility requirements, whichever is greater. If the steam export is less than 110,000 lb/hr, an appropriate downward correction will be applied pursuant to the Evaluation of Test Results section of this document.

8. The power factor during the Test shall be as close as possible to 0.85 at full load for at least 30 to 60 minutes, if HECO Dispatch can accommodate such, to ensure the Facility is able to operate with the increased load at the contractual minimum power factor required by the PPA. The power factor during the Test may range anywhere within the specifications of Section 2.1D of the PPA.

9. The Facility shall operate at normal and representative operating conditions under control of HECO Dispatch consistent with the terms and conditions of the PPA.

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Operation during any portion of the Test outside of these conditions shall entitle Kalaeloa to repeat such portion of the Test.

10. Kalaeloa shall perform the Test in full compliance with all of its current operating permits, including the Covered Source Permit. Where no continuous emission monitoring is required by permit to document compliance, Kalaeloa shall, during the Test, demonstrate to HECO’s satisfaction that the Facility is continuously capable of complying with its Covered Source Permit at all output levels between 65MW and the capacity capability demonstrated by the Test.

11. Kalaeloa provided written documentation to HECO’s satisfaction that all Facility modifications made subsequent to the initial design and construction of the Facility are in compliance with applicable environmental laws and regulations, and permits so that the Facility can operate under HECO Dispatch with all modifications subsequent to its original design and construction, and the continuous operation of the Facility for future periods at the capacity level for two CT operation and once CT operation demonstrated in the Test will not be limited or restricted in any way as a result of a condition contained in any permit.

12. HECO’s evaluation of the capability level demonstrated by two CT operation and one CT operation within this Test shall be based on the minimum average capacity level that the Facility is able to sustain over each One Clock Hour Average (as defined below), as recorded by the revenue meters after the adjustment by any correction factor as discussed herein, in which the Facility is being dispatched at full load during the Test and in which the Facility adheres to all operational parameters set forth herein. Capacity data shall only be valid once the Facility is stable at full load. Stable full load is defined by operation at full firing temperature and inlet guide vanes at 0 +/- 0.3, and that these conditions exist for at least one hour prior to the measurement hour in order to allow the Facility’s steam cycle to reach equilibrium. Operation at this mode shall be continuous at the discretion of HECO’s Load Dispatcher. These values are used to mitigate any short-term variations and to correspond to hourly average Facility supplemental data used for corrections of the results to the Test results.

13. Kalaeloa shall provide a certificate of calibration for all instrumentation pertinent to the operational parameters listed herein.

14. Kalaeloa shall provide written confirmation that no abnormal events occurred during the Test with the various Facility equipment and that the operating modes were within a range of that can be sustained on a continuous mode of operation under HECO Dispatch.

General Information

1. The Facility shall be operated by ALSTOM personnel.

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2. HECO’s Load Dispatcher shall allow operation of the Facility at full load as much as practical consistent within dispatch requirements of the HECO system. This can include dispatch of the Facility at the Net Electrical Energy Output as low as 65,000 KW. Testing can be interrupted or terminated at any time by any party should such be necessary to protect the safety of personnel, equipment or system stability but shall be re-commenced once such situation is rectified.

3. HECO may, at its discretion, dispatch observers to the Facility to monitor testing as HECO deems necessary. HECO’s observers shall not interfere with operations, nor shall they direct/supervise ALSTOM’s operators in any manner. However, should they find issues that may compromise the quality of the testing or data, such issues shall be discussed with ALSTOM management and Kalaeloa.

4. Following are contact people for each organization. Additional contact information for the Facility will be provided upon request:

• Contact person for HECO is Ward Saunders – Contract Administrator

• Contact person for Kalaeloa is Ruedi Tobler – General Manager

• Contact person for ALSTOM is Mike Rossio – Operations Manager

5. Data shall be collected using installed Facility instrumentation, except as listed under “Evaluation of Test Results” item # 1.

Test Set Up

1. First test run for the full Facility case shall start on a Wednesday at 13:00 and shall end on the first Friday thereafter at 13:00. Each of the one CT operation portion of the Test run shall start on a Saturday at 13:00 and end 4-hours later. In general the second 4-hour run would be on the following Saturday or a subsequent Saturday as soon as the HECO system can accommodate such portion of the Test.

2. Additional testing, if necessary, shall be conducted if agreed to by HECO and Kalaeloa.

3. Normal and routine turbine, compressor and HRSG washing schedules shall be followed between the time this Test procedure is agreed and conclusion of Testing and in no case shall normal washing of the turbines, compressors and HRSG’s actually occur more frequently than weekly with the exception of daily on line compressor washes.

4. Normal full load operating conditions of the Facility as follows:

• evaporative coolers in service

• stack heat exchangers in service

• fuel: LSFO (specification sheet attached)

• variable inlet guide vane (“VIGV”) setting: zero

• TIT setpoint: 1854F

4

• steam injection: minimum steam-to-fuel ratio 1.3, maximum 1.5 or greater if needed to maintain emissions within permit limits.

• process steam total: as needed by Tesoro

• Power Factor: as dispatched by HECO between 0.85 lagging to 1.0

5. Data shall be collected by the Facility’s data acquisition system.

KALAELOA Procedure

1. Start at 12:00 on day of that portion of the Test by taking the Facility to full load if consistent with load dispatch requirements. For the one CT Test, the CT being tested shall be synchronized, the steam turbine shall be synchronized and the other CT shall not be synchronized.

2. Check to see that performance computer is not locked up, and verify that fuel data are updated.

3. Take Facility off Energy Management System (“EMS”) with concurrence of HECO’s Load Dispatcher and set at baseload conditions: TIT = 1854 °F, max., VIGV at 0°, additive at normal rate, process steam as needed by Tesoro.

4. Allow Facility to stabilize at the above conditions until 13:00 at which time print out the following Praut diagrams:

•     P02	•     P25
•     P06	•     P26
•     P04	•     P27
•     P09	•     P37
•     P12	•     Bar 16
•     P20

5. If conditions appear stable about 13:00, call HECO’s Load Dispatcher and declare that Testing is under way. Make entry in log book.

6. One hour after start of Test, print out the same data sheets as listed above. Also, around that time, take a fuel sample from LSFO forwarding system.

7. Test will run 48 hours from that point for the case of full Facility capability or 4-hours for the portion of the Test which tests capability without the second CT synchronized. If HECO needs the Facility back on EMS, do so and make a note in the log. Continue to respond to HECO’s load needs as per normal operating practices.

8. If operating conditions change such that Facility load drops below full load in dual CT mode or in single CT mode, make an entry in the log book indicating time that such reduction started, reason for reduction, and print out any PRAUT data that may help

5

provide information on this type of condition. When the Facility is restored to full load, make the appropriate entry in the log book.

9. Hourly, check that RADARS is continuing with data collections.

10. Log time whenever fuel tanks are switched. Take a fuel sample at LSFO forwarding about 1 hour after the tanks are switched.

Evaluation of Test Results

1. HECO shall poll its revenue meters (KW and KVAR) and make results available to Kalaeloa soon after the Test (but within 3 working days in any event).

2. The minimum full load One Clock Hour Average shall establish the uncorrected capacity of the Facility. The One Clock Hour Average is defined as the four consecutive 15 minute periods beginning with the reading for the 15 minute period that ends at 15 minutes past the hour. These values are used to mitigate any short-term variations and to correspond to hourly average Facility supplemental data used for corrections to the capacity measured during the Test.

3. The lowest full load One Clock Hour Average of each of the three turbines in that hour shall be corrected to the following parameters as applicable in accordance with the correction factors determined from the charts to be provided to HECO which include the ASHRAE design conditions determined at 0.4% annual percentile for Barbers Point NAS (now Kalaeloa National Weather Service site) (the “ASHRAE Design Conditions”):

Variable	-	Corrected to:
Compressor Inlet Temperature		77F. Based on ASHRAE Design Conditions of 76F wet bulb, 86F coincident dry bulb, for CT correction with evaporative coolers in service
Ambient Temperature		86F. Based on ASHRAE Design Conditions of 76F wet bulb, 86F coincident dry bulb for ST correction
Ambient Humidity	-	64%. Based on ASHRAE Design Conditions of 76F wet bulb, 86F coincident dry bulb
Ambient Pressure	-	14.8 psia. Average barometric pressure for August 15 to September 15 at 13:00 (from Kalaeloa’s operational data)
Power Factor		0.85 lagging

6

Export Steam Up to110,000 lbs/hr (or value necessary for Facility to achieve PURPA requirements). No correction above 110,000 lbs/hr

If the actual temperature and humidity conditions exceed the ASHRAE Design Conditions, no corrections will be made to the KW output of any of the three turbines. The 0.4% annual percentile ASHRAE Design Conditions represent a ceiling for reasonably anticipated worst-case conditions.

The Test results for the two portions of the Test relating to each CT will need to be corrected per PPA Attachment D to correct to the approximate time prescribed for the Test of each CT relative to the need for a “C” inspection pursuant to Test Conditions and Parameters, Item 4, if that portion of the Test does not occur when prescribed by such Item 4. A determination of which CT result is corrected to 8,000 operating hours vs 16,000 operating hours is made after performing the calculation for both combinations of CTs (i.e. CT1 for 8,000 and CT2 for 16,000 vs CT1 for 16,000 and CT2 for 8,000). The combination of operating hour correction pairs to be applied is the average of the two cases, however, if any of the combinations requires that a correction be applied where the degradation is calculated to a CT for an operating hour level that has already occurred in the present C inspection interval, no correction is applied for that CT for purposes of the specific combination calculation. An example of the calculations is attached.

The corrected capacity for the full Facility shall be rounded to the nearest MW output with decimal values of 0.50 and higher being round up to the next integer MW value and decimal values of 0.49 or less being rounded down to the next integer MW value and shall be the capability level demonstrated for the full Facility case by the Test.

To determine the capability of the Facility without one CT in operation, the lowest capability test result level of the two test runs will be used for the test result. The corrected capacity shall be the value in MW truncated to the integer level.

In order to facilitate evaluation of the Test results and the influence of the Facility modifications, the following shall be provided:

Correction curves for CT:

1.) Compressor Inlet Temperature

2.) Power Factor

3.) Ambient Humidity

Correction curves for ST:

1.) Ambient Temperature and Ambient Humidity

2.) Ambient Pressure

3.) Power Factor

4.) HP steam export

5.) IP steam export

6.) LP steam export

7

The following data shall be collected by Kalaeloa during the Test to be used for correcting the measured capacity from the Test results to the herein defined reasonable worst-case conditions:

• date (with day of week shown separately)

• date of last “C” inspection for each CT

• date each HRSG last cleaned

• time (13:00)

• Ambient Temperature

• Ambient Humidity

• Ambient Pressure

• evaporative cooler on?

• dispatched at full load?

• TIT

• steam to fuel ratio, each CT

• steam export to Tesoro

• CT1 MW

• CT2 MW

• total facility MW

• fuel flow, each CT

• steam turbine MW

• steam turbine exhaust pressure.

• steam turbine throttle pressure

• steam turbine throttle temperature

• CT1 stack exhaust temperature

• CT2 stack exhaust temperature

• fuel analysis (including fuel bound nitrogen)

• VIGV data

• listing of all CT washes, compressor washes (on-line and off-line), boiler washes within 45 days of the start of the test.

• list the Equivalent Operating Hours (EOH) of each CT since the last “C” inspection and the EOH of the ST since the last major inspection.

8

Example 1

Assumptions

1. CT Unit No. 1 M Upgrade commences operation on June 1^st, 2004.

2. CT Unit No. 2 M Upgrade commences operation on December 31^st, 2004.

3. All three portions of the Test are completed by January 30, 2005 and on January 30, 2005 the log book reveals that:

(i) 5,830 operating hours have elapsed on CT Unit No. 1; and

(ii) 720 operating hours have elapsed on CT Unit No. 2.

4. All operating conditions and ASHRAE Design Conditions corrections have been applied to Preliminary Results.

5. The lower border of the lower right curve on Figure 3 of Attachment D to the PPA (the “Output Degradation Curve”) will be used to measure output degradation of the CTs. Since the data source for the equation for the Output Degradation Curve is not available at the present time and it is presumed that the equation will not be available at the time of the Test, the parties will visually and by means of a ruler, extract the Output Degradation Curve changes in a reasonable manner and it is agreed that the extracted values from the Output Degradation Curve which are used in the example below are not to be deemed to be official readings from the Output Degradation Curve but rather reasonably approximated values for purposes of illustration in the example below.

6. ST degradation is assumed to be negligible based on the estimated potential of the HRSG to produce steam. Thus, HRSG steam output would not be expected to substantially change throughout the C inspection cycle.

Preliminary Results

7. The Test’s 48 hour portion demonstrates the lowest full load One Clock Hour Average for the Facility is 210,000 KW and during the same hour the One Clock Hour Average for CT Unit No. 1 is 79,040 KW and the One Clock Hour Average for CT Unit No. 2 is 80,960 KW.

8. The Test’s 4 hour portion for CT Unit No. 1 demonstrates the lowest full load One Clock Hour Average for CT Unit No. 1 and the ST is 102,870 KW of which the One Clock Hour Average for the same hour is 78,870 KW for CT Unit No. 1 and 24,000 KW for the ST.

9. The Test’s 4 hour portion for CT Unit No. 2 demonstrates the lowest full load One Clock Hour Average for CT Unit No. 2 and the ST is 105,130 KW of which the One Clock Hour Average for the same hour is 81,130 KW for CT Unit No. 2 and 24,000 KW for the ST.

Degradation Correction for the 48 Hour Portion of the Test

10. (a) Correction of the 48 hour test portion requires correcting the One Clock Hour Average (which occurred during the lowest full load One Clock Hour Average for the Facility) for each of CT Unit No. 1 and CT Unit No. 2 to allow for degradation as contemplated by the Output Degradation Curve. Two cases will be calculated and the

result averaged. In the first case, CT Unit No. 1 will be degraded to 8,000 hours and CT Unit No. 2 will be degraded to 16,000 hours. In the second case, CT Unit No. 1 will be degraded to 16,000 hours and CT Unit No. 2 will be degraded to 8,000 hours. The cases will then be averaged.

Case One

(b) For CT Unit No. 1 the degradation shall be 0.47% which represents the additional degradation which the Output Degradation Curve predicts would occur if CT Unit No. 1 had been tested at the 8,000 operating hour mark (CT Unit No. 1 has already degraded during its 5,830 hours of operation since June 1^st, 2004) which is the state at which CT No. 1 should be deemed to be halfway through its “C” inspection life cycle. Thus, 0.47% was determined by calculating the degradation which the Output Degradation Curve predicts would occur for the 2,170 operating hours from hour 5,930 until hour 8,000. Therefore, the CT Unit No. 1 reading (during the Facility’s lowest full load One Clock Hour Average) of 79,040 KW is multiplied by (100% - 0.47%) which equals 78,669 KW for CT Unit No. 1.

(c) For CT Unit No. 2 the degradation shall be 2.74% which represents the additional degradation which the Output Degradation Curve predicts would occur if CT Unit No. 2 had been tested at the 16,000 operating hour mark (CT Unit No. 2 has already degraded during its 720 hours of operation since December 31^st, 2004) which is the state at which CT No. 2 should be deemed to be at the end of its “C” inspection life cycle. Thus, 2.74% was determined by calculating the degradation which would occur for the 15,280 operating hours from hour 720 until hour 16,000. Therefore, the CT Unit No. 2 reading (during the Facility’s lowest full load One Clock Hour Average) of 80,960 KW is multiplied by (100% - 2.74%) which equals 78,742 KW for CT Unit No. 2.

(d) Correction to the 48 hour portion shall be 210,000 – ((79,040 - 78,669) + (80,960 - 78,742)) = 207,411 which represents the lowest full load One Clock Hour Average of the Facility less the Output Degradation Curve degradation calculated in (b) and (c) above for the CTs.

Case Two

(e) For CT Unit No. 1 the degradation shall be 1.28% which represents the additional degradation which the Output Degradation Curve predicts would occur if CT Unit No. 1 had been tested at the 16,000 operating hour mark (CT Unit No. 1 has already degraded during its 5,830 hours of operation since June 1^st, 2004) which is the state at which CT No. 1 should be deemed to be at the end of its “C” inspection life cycle. Thus, 1.28% was determined by calculating the degradation which the Output Degradation Curve predicts would occur for the 10,170 operating hours from hour 5,930 until hour 16,000. Therefore, the CT Unit No. 1 reading (during the Facility’s lowest full load One Clock Hour Average) of 79,040 KW is multiplied by (100% - 1.28%) which equals 78,028 KW for CT Unit No. 1.

(f) For CT Unit No. 2 the degradation shall be 1.93% which represents the additional degradation which the Output Degradation Curve predicts would occur if CT Unit No. 2 had been tested at the 8,000 operating hour mark (CT Unit No. 2 has already degraded during its 720 hours of operation since December 31^st, 2004) which is the state at which

2

CT No. 2 should be deemed to be halfway through its “C” inspection life cycle. Thus, 1.93% was determined by calculating the degradation which would occur for the 7,280 operating hours from hour 720 until hour 8,000. Therefore, the CT Unit No. 2 reading (during the Facility’s lowest full load One Clock Hour Average) of 80,960 KW is multiplied by (100% - 1.93%) which equals 79,397 KW for CT Unit No. 2.

(g) Correction to the 48 hour portion shall be 210,000 – ((79,040 - 78,028) + (80,960 – 79,397)) = 207,425 which represents the lowest full load One Clock Hour Average of the Facility less the Output Degradation Curve degradation calculated in (e) and (f) above for the CTs.

(h) Finally, the average of 207,411 KW and 207,425 KW is taken yielding 207,418 KW.

Degradation Corrections for 4 Hour Portion of the Test Relating to CT Unit No. 1

11. Correction to CT Unit No. 1 shall be 1.28% which represents the additional degradation which the Output Degradation Curve predicts would occur for the 10,170 operating hour from hour 5,830 until operating hour 16,000 (CT Unit No. 1 has already degraded during its 5,830 hours of operation since June 2004) which is the state at which CT No. 1 should be deemed to be halfway through its “C” inspection life cycle. Thus, 1.28% was determined by calculating the degradation which would occur from operating hour 5,830 until hour 16,000. Therefore, the CT Unit No. 1 lowest full load One Clock Hour Average of 78,870 KW is multiplied by (100% - 1.28%) which equals 77,860 KW for CT Unit No. 1. 101,860 KW is the result of the 4 hour portion of the Test for CT Unit No. 1 (77,860 KW for CT Unit No. 1 plus the ST of 24,000 KW).

Degradation Correction for 4 Hour Portion of the Test Relating to CT Unit No. 2

12. Correction to CT Unit No. 2 shall be 2.74% which represents the additional degradation which the Output Degradation Curve predicts would occur from operating hour 720 until operating hour 16,000 (CT Unit No. 2 has already degraded during its 720 operating hours of operation since its “C” inspection) which is the state at which CT No. 2 should be deemed to be at the end of its “C” inspection life cycle. Thus, 2.74% was determined by calculating the degradation which would occur for the 15,280 operating hours from operating hour 720 until operating hour 16,000. Therefore, the CT Unit No. 2 lowest full load One Clock Hour Average of 81,130 KW is multiplied by (100% - 2.74%) which equals 78,907 KW for CT Unit No. 2. 102,907 KW is the result of the 4 hour portion of the Test for CT Unit No. 2 (78,907 KW for CT Unit No. 2 plus the ST of 24,000 KW).

Test Results

13. Full Facility capability is 207,000 KW (which represents 207,418 KW rounded to 207,000 KW).

14. Partial Facility capability is 101,000 KW which is the lower of the capabilities of 101,860 KW and 102,907 KW as such result is truncated in accordance with the protocol.

Increment Two Capacity Agreement Results

15. Demonstrated Facility Capacity is 207,000 KW.

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16. Increment Two Capacity is set at 18,000 KW which represents the first 18,000 KW beyond the Baseline Capacity of 180,000 KW plus the Increment One Capacity of 9,000 KW.

17. New Capacity is 27,000 KW which is the Increment One Capacity of 9,000 KW plus the Increment Two Capacity of 18,000 KW.

18. Prorated Shutdown Capacity is set at 101,000 KW which is the highest of 90,000 KW and 101,000 KW.

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EXHIBIT 4

30-Jun-04

Mr. Ward D. Sauders, P.E.

Purchased Power Contract Administrator

Hawaiian Electric Company, Inc.

P.O. Box 2750

Honolulu, HI 96840-0001

Subject: Calculation of Value of the Facility

Dear Ward,

At your request, we have prepared the calculation of the value of the Facility as specified under PPA Sections 3.3 (H) and 7.2 B (1). These calculations include the outstanding principal on the project debt as of June 30, 2004. Since we make quarterly debt service payments, this debt value will be the same until September 30, 2004. Please see the enclosed.

Sincerely,

Kalaeloa Partners, L.P.

By:	PSEG Kalaeloa Inc.
	Its General Partner
By	/s/ Royal Daniel
	Royal Daniel
	Its Vice President

(Enclosures)

Kalaeloa Partners, L.P.

Calculation of PPA 3.3 (H) Value as of 6/30/04

PPA Section 3.3(H) Loss of QF Status
	Outstanding Debt (1)		$	154,198,500
+	Obligations under steam sales contract			—
+	Obligations under site lease			—
+	Turnkey Design/Build Contract			—
+	Operating, maintenance and Repair Contract			—
+	Fuel Supply Contract			—
+	Kalaeloa original equity investment less distributions (2)			—
		Total	$	154,198,500

Footnotes:
	(1)	Outstanding Debt:
		Bank loan current balance after quarterly payment on 6/30/04	$	36,579,750
		Institutional loan current balance after quarterly payment on 6/30/04		117,618,750
		Total (As of 6/30/04)	$	154,198,500

(2)    Kalaeloa partners investments and distributions
	Investment		Distribution
1989 Investment	$	1,016,433
1989 Distribution			$	1,612,566
1991 Investment		14,361,064
1992 Distribution				8,711,952
1993 Distribution				5,039,345
1994 Distribution				6,462,618
1995 Distribution				4,566,365
1996 Distribution				—
1997 Distribution				15,188,983
1998 Distribution				9,354,933
1999 Distribution				3,633,000
2000 Distribution				6,168,857
2001 Distribution				10,229,529
2002 Distribution				1,854,003
2003 Distribution				5,832,546
2004 Distribution				1,191,214
	$	15,377,497	$	79,845,911
Investment less Distribution not less than zero. Kalealoa will not include the PSEG purchase price of $54.4 million as an original investment.

Kalaeloa Partners, L.P.

Calculation of PPA 7.2 B (1) Value as of 6/30/04

PPA Section 7.2 B (1), Amendment 3- HECO’s assumption of Kalaeloa’s Interest upon default

	Outstanding Debt (1)		$	154,198,500
+	Other obligations			—
+	Fair market value (FMV) of Facility (2)			110,000,000
-	Stated amount per Amendment			(30,000,000	)
-	$8.5 million x (A/B) (3)			(5,890,729	)
	Total		$	228,307,771
Footnotes
	(1)	See footnote1, previous page
	(2)	Hypothetical fair market value based on recent market price indication rounded to the nearest $10,000,000 (actual fair market value would be based on average of 3 appraisals)
	(3)	A is outstanding principal	$	154,198,500
		B is initial principal	$	222,500,000
		A/B is:		0.6930
		$8,500,000 x 0.6930	$	5,890,729

ATTACHMENT G

General Plant Description

The KALAELOA Combined Cycle Facility will be constructed in two phases as follows:

a. Phase 1, consisting of a simple cycle facility with one combustion turbine Type GT11N to generate electricity for, “peaking” service; and

b. Phase 2, the Combined Cycle Facility with one additional combustion turbine Type GT11N and one steam turbine to generate steam for sale to Tesoro Hawaii, Corp. (Tesoro) (formerly HIRI) and electricity for HECO dispatch.

The Combined Cycle Cogeneration Facility will be located on the island of Oahu in the Campbell Industrial Park. The proposed site is located approximately twenty (20) miles west of Honolulu. A legal description of the site is provided in Attachment F. The Facility will consist of state of the art components, systems, and redundancy to allow the plant to meet the availability guarantees contained in the PPA. All plant equipment will be designed to provide a plant life of at least thirty (30) years.

The Facility will consist of two ABB type GT11N gas turbine generators with a nominal rating each of 74,600 kilowatts (76°F, 14.69 PSIA). Both of these combustion turbines are equipped with the NM upgrade package and now have a nominal rating of 86,000 kilowatts (76 deg F, 14.69 PSIA). The gas turbine exhaust flow will pass through two dual pressure heat recovery steam generators (HRSG) with each HRSG generating approximately 260,000 Lb/Hr of 905°F/1108 PSIA superheated steam and 97,000 Lb/Hr of 322°F/90 PSIA saturated steam at design conditions. LSFO will be the primary fuel for the gas turbines with No. 2 distillate fuel oil serving as the back-up fuel.

The 1108 PSIA steam will pass from the HRSG high pressure drum and enter a 51,900 kilowatt extraction condensing steam turbine (with Tesoro design steam requirements) generator. Steam will be extracted from the steam turbine, desuperheated, and sent to Tesoro under conditions specified in the Steam Purchase Agreement contained in Attachment N.

During the operation of Phase 1, water injection will be used for NOx control. Steam will be used for gas turbine NOx control during Phase 2. Steam from the extraction/condensing turbine will exhaust into a condenser operating at 2.66 inches HGA. The condenser will be cooled by water from a salt water well system. Condensate collected in the condenser hot well will be pumped via condensate pumps thru two stages of feedwater heating to the deaerator. The unit will be equipped with steam jet air ejectors. After exiting the deaerator, two HP feed pumps will supply feedwater to the HP sections of the HRSGs. Two LP feed pumps will supply the feedwater to the LP sections of the HRSG’s.

The source of makeup water for the plant steam cycle will be city potable or city reverse osmosis recycled water. Once that water is demineralized it will be discharged into a demineralized water storage tank. The demineralized water will serve as the markup for the auxiliary boiler and the cogeneration plant steam cycle. The makeup water will enter the steam cycle after the No. 2 low pressure heater. Demineralized boiler feedwater will be returned from the refinery and enter the steam cycle at this location also.

The Phase 1 fuel will be a gaseous fuel supplied by HIRI. The LSFO primary fuel for the Combined Cycle Facility and No. 2 distillate Phase 2 backup fuel oil will be provided by Tesoro. A vanadium inhibitor will be added to the LSFO at the Facility.

The cogeneration facility will be configured and instrumented to control and measure discharges/emissions in accordance with applicable environmental permits.

2

Attachment R

Explanation of Quick

Load Pick-up Curves

The starting point for the curve shown in HTGK 100 336 is two CTs plus the ST in operation at 115 MW (45 MW for each CT and 25 MW for ST at design conditions of 76°F). At time 0, we will have a frequency drop from 60 Hz to 59.5 Hz. The gas turbines would then pick up to 20% of their full load to reach point (1) after approximately 6 seconds. The setting value for power output of the gas turbines has then to be set to full load with the high gradient. The gas turbine will be loaded accordingly at 9.5 MW/min beginning in second 7. The steam turbine will also increase load with a certain time spent between rising of gas turbine load and steam turbine load, due to the inertia of piping and boiler. At point (2) the gas turbines have reached full load, the remaining load increase will then only come from the steam turbine.

The starting point for the curve shown in HTGK 400 337 is one CT plus ST in operation at 65 MW (45 MW for CT and 20 MW for ST at design conditions of 76°F). At time 0 we will have a frequency drop from 60 Hz to 59.5 Hz. The gas turbine would then pick up 20% of its full load to reach point (1) after approximately 6 seconds. The setting value for power output of the gas turbine I has then to be set to full load with the high gradient. At the same time the gas turbine II has to be quick-started according to HTCT 70 907/a “Quick Start.” We will then reach point (2). From (2) to (3) the load increase comes only from the load increase of the steam turbine. At (4) the gas turbine is synchronized and loaded at 9.5 MW/min. At (5) the bypass of HRSG II is starting to close. The pressure gradient of both boilers is controlled by the bypass to a maximum gradient of 4 bar/min. From (5) to (6) the load increase comes from gas turbine II and the steam turbine. After (6) the load increase is only given by the steam turbine.

General Comments on Load Pick-ups

If the temperature controller is not at the maximum inlet temperature, the speed controller of the gas turbine reacts according to a statism of 4%, every time a frequency drop

occurs. If the CT load is higher than ~ 83% (maximum inlet temperature reached), the gas turbine will no longer react to a frequency drop, as was the case with the speed controller in operation, but only with a gradient of approximately 3.4 - 9.5 MW/min, depending on which figure is set. The steam turbine would react according to the steam production.

Y-2

ATTACHMENT W

Capacity Charge Calculation

(Unavailability Adjustment)

This computation is provided as an illustration of how to compute a Capacity Charge adjustment pursuant to Section 5.2A(4) for a hypothetical partial unavailability of the Facility.

Example I – Unavailability in excess of 10MW for 30 days or more

Assumptions:	Baseline Capacity = 180MW
	Capacity Charge for Baseline Capacity = $164.35/KW-yr
	($164.35 is the value effective 12/19/91 per PPA, Restated and Amended Amendment 2, Section 3.)
	New Capacity = 29MW
	Capacity Charge for New Capacity = $112.00/KW-yr
	Capacity deficiency = 38 MW
	Duration of capacity deficiency = 42 days; 0 hours; 0 minutes
	Period of capacity deficiency = April 20 (00:00) – May 31(24:00)

Impact on Capacity Charge:

Month of April means payment due in April for Energy received by HECO in March and Capacity to be received by HECO in April.

Month of April – no impact (capacity paid in advance)

Month of May – no impact (capacity paid in advance)

Month of June – normal payment =

[	180,000 KW	x	164.35 / Kwyr	]    +    [	29,000 KW	x	112.00 / Kwyr	]
			12mo/ yr				12mo/ yr

= $2,735,916.67

adjustment to payment	=	[	9,000	x	42.00	x	164.35	]    +    [	29,000	x	42.00	x	112.00	]
					365						365

= $543,946.03 reduction

NOTE:

If deficiency for the same period had been 209 MW, adjustment to the Month of June would be $2,735,916.67 and the balance ($1,041,897.03 in this case) would be deducted from Month of July Capacity Charge payment due to Kalaeloa.

1

Example II – Unavailability of 10MW or less for more than 120 days

Assumptions:	Capacity deficiency = 10 MW
	Duration of capacity deficiency = 121 days; 0 hours; 0 minutes
	Period of capacity deficiency = April 20 – August 18

Impact on Capacity Charge:

Months of April to September – no impact (capacity paid in advance)

Month of October – normal payment =

[	180,000 KW	x	164.35 / Kwyr	]    +    [	29,000 KW	x	112.00 / Kwyr	]
			12mo/ yr				12mo/ yr

= $2,783,316.67

adjustment to payment	=	[	10,000	x	121.00	x	112.00	]
					365

= $371,287.67 reduction

2

EX-12.2

HECO Exhibit 12.2 (page 1 of 2)

Hawaiian Electric Company, Inc. and Subsidiaries

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

(unaudited)

Nine months ended September 30	2004			2003
(dollars in thousands)
Fixed charges
Total interest charges	$	37,575		$	34,055
Interest component of rentals		612			625
Pretax preferred stock dividend requirements of subsidiaries		1,112			1,094
Preferred securities distributions of trust subsidiaries		—			5,756
Total fixed charges	$	39,299		$	41,530
Earnings
Income before preferred stock dividends of HECO	$	68,743		$	57,382
Income taxes (see note below)		43,055			36,777
Fixed charges, as shown		39,299			41,530
AFUDC for borrowed funds		(2,236	)		(1,385	)
Earnings available for fixed charges	$	148,861		$	134,304
Ratio of earnings to fixed charges		3.79			3.23
Note: Income taxes is comprised of the following
Income tax expense relating to operating income from regulated activities	$	43,454		$	36,865
Income tax benefit relating to results from nonregulated activities		(399	)		(88	)
	$	43,055		$	36,777

HECO Exhibit 12.2 (page 2 of 2)

Hawaiian Electric Company, Inc. and Subsidiaries

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

(unaudited)

(continued)

Years ended December 31	2003			2002			2001			2000			1999
(dollars in thousands)
Fixed charges
Total interest charges	$	44,341		$	44,232		$	47,056		$	49,062		$	48,461
Interest component of rentals		820			663			728			696			784
Pretax preferred stock dividend requirements of subsidiaries		1,430			1,434			1,433			1,438			1,479
Preferred securities distributions of trust subsidiaries		7,675			7,675			7,675			7,675			7,665
Total fixed charges	$	54,266		$	54,004		$	56,892		$	58,871		$	58,389
Earnings
Income before preferred stock dividends of HECO	$	79,991		$	91,285		$	89,380		$	88,366		$	76,400
Fixed charges, as shown		54,266			54,004			56,892			58,871			58,389
Income taxes (see note below)		49,824			56,658			55,416			55,375			48,047
Allowance for borrowed funds used during construction		(1,914	)		(1,855	)		(2,258	)		(2,922	)		(2,576	)
Earnings available for fixed charges	$	182,167		$	200,092		$	199,430		$	199,690		$	180,260
Ratio of earnings to fixed charges		3.36			3.71			3.51			3.39			3.09
Note: Income taxes is comprised of the following:
Income tax expense relating to operating income from regulated activities	$	50,175		$	56,729		$	55,434		$	55,213		$	48,281
Income tax expense (benefit) relating to results from nonregulated activities		(351	)		(71	)		(18	)		162			(234	)
	$	49,824		$	56,658		$	55,416		$	55,375		$	48,047

EX-31.3

HECO Exhibit 31.3

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

I, T. Michael May, certify that:

1. I have reviewed this report on Form 10-Q for the quarter ended September 30, 2004 of Hawaiian Electric Company, Inc. (“registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 5, 2004

/s/    T. MICHAEL MAY        

T. Michael May

President and Chief Executive Officer

EX-31.4

HECO Exhibit 31.4

Certification Pursuant to Section 13a-14 of the Securities Exchange Act of 1934 of Tayne S. Y. Sekimura (HECO Chief Financial Officer)

I, Tayne S. Y. Sekimura, certify that:

1. I have reviewed this report on Form 10-Q for the quarter ended September 30, 2004 of Hawaiian Electric Company, Inc. (“registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 5, 2004

/s/    TAYNE S. Y. SEKIMURA        

Tayne S. Y. Sekimura

Financial Vice President

EX-32.3

HECO Exhibit 32.3

Hawaiian Electric Company, Inc.

Written Statement of Chief Executive Officer Furnished Pursuant to

18 U.S.C. Section 1350,

as Adopted by

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of Hawaiian Electric Company, Inc. (HECO) on Form 10-Q for the quarter ended September 30, 2004 as filed with the Securities and Exchange Commission (the HECO Report), I, T. Michael May, Chief Executive Officer of HECO, certify, pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1) The HECO Report fully complies with the requirements of section 13(a) of the Securities Exchange Act of 1934; and

(2) The HECO consolidated information contained in the HECO Report fairly presents, in all material respects, the financial condition as of September 30, 2004 and results of operations for the three and nine months ended September 30, 2004 of HECO and its subsidiaries.

/s/    T. MICHAEL MAY        

T. Michael May

President and Chief Executive Officer of HECO

Date: November 5, 2004

A signed original of this written statement required by Section 906 has been provided to Hawaiian Electric Company, Inc. and will be retained by Hawaiian Electric Company, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.4

HECO Exhibit 32.4

Hawaiian Electric Company, Inc.

Written Statement of Chief Financial Officer Furnished Pursuant to

18 U.S.C. Section 1350,

as Adopted by

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of Hawaiian Electric Company, Inc. (HECO) on Form 10-Q for the quarter ended September 30, 2004 as filed with the Securities and Exchange Commission (the HECO Report), I, Tayne S. Y. Sekimura, Chief Financial Officer of HECO, certify, pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1) The HECO Report fully complies with the requirements of section 13(a) of the Securities Exchange Act of 1934; and

(2) The HECO consolidated information contained in the HECO Report fairly presents, in all material respects, the financial condition as of September 30, 2004 and results of operations for the three and nine months ended September 30, 2004 of HECO and its subsidiaries.

/s/    TAYNE S. Y. SEKIMURA        

Tayne S. Y. Sekimura

Financial Vice President of HECO

Date: November 5, 2004

A signed original of this written statement required by Section 906 has been provided to Hawaiian Electric Company, Inc. and will be retained by Hawaiian Electric Company, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.