Edgar Filing: HAWAIIAN ELECTRIC CO INC

Page/s in Form 10-K/A

Independent Auditors’ Report

Schedule I

Condensed Financial Information of Registrant, Hawaiian Electric Industries, Inc. (Parent Company) as of December 31, 2003 and 2002 and Years ended December 31, 2003, 2002 and 2001

Schedule II

Valuation and Qualifying Accounts, Years ended December 31, 2003, 2002 and 2001

Amendment #1 to Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K/A

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

For the fiscal year ended December 31, 2003

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


Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	I.R.S. Employer Identification No.
1-8503	HAWAIIAN ELECTRIC INDUSTRIES, INC., a Hawaii corporation (HEI) 900 Richards Street, Honolulu, Hawaii 96813 Telephone (808) 543-5662	99-0208097
1-4955	HAWAIIAN ELECTRIC COMPANY, INC., a Hawaii corporation (HECO) 900 Richards Street, Honolulu, Hawaii 96813 Telephone (808) 543-7771	99-0040500

Securities registered pursuant to Section 12(b) of the Act:


Registrant	Title of each class	Name of each exchange on which registered
Hawaiian Electric Industries, Inc.	Common Stock, Without Par Value	New York Stock Exchange
Hawaiian Electric Industries, Inc.	Guarantee with respect to 8.36% Trust Originated Preferred Securities ^SM (TOPrS ^SM)	New York Stock Exchange
Hawaiian Electric Industries, Inc.	Preferred Stock Purchase Rights	New York Stock Exchange
Hawaiian Electric Company, Inc.	Guarantee with respect to 8.05% Cumulative Quarterly Income Preferred Securities Series 1997 (QUIPS^SM)	New York Stock Exchange
Hawaiian Electric Company, Inc.	Guarantee with respect to 7.30% Cumulative Quarterly Income Preferred Securities Series 1998 (QUIPS^SM)	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:


Registrant		Title of each class
Hawaiian Electric Industries, Inc.		None
Hawaiian Electric Company, Inc.		Cumulative Preferred Stock

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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


	Aggregate market value of the voting common equity held by non-affiliates of the registrants on June 30, 2003	Number of shares of common stock outstanding of the registrants on March 1, 2004
Hawaiian Electric Industries, Inc. (HEI)	$1,715,658,628.25	38,032,319 (Without par value)

Hawaiian Electric Company, Inc. (HECO)	Not applicable	12,805,843 ($6 2/3 par value)

DOCUMENTS INCORPORATED BY REFERENCE

HEI Annual Report to Shareholders for the fiscal year ended December 31, 2003—Parts I, II, III and IV

HECO Consolidated 2003 Financial Statements—Parts I, II, III and IV

Portions of Proxy Statement of Hawaiian Electric Industries, Inc., dated March 9, 2004 for the 2004 Annual Meeting of Shareholders—Part III

This combined Form 10-K/A represents separate filings by Hawaiian Electric Industries, Inc. and Hawaiian Electric Company, Inc. Information contained herein relating to any individual registrant is filed by each registrant on its own behalf. Neither registrant makes any representations as to the information relating to the other registrant.

EXPLANATORY NOTE:

This amendment to the annual report on Form 10-K of registrants Hawaiian Electric Industries, Inc. (HEI) and Hawaiian Electric Company, Inc. (HECO) is being filed solely to correct Item 7 relating to HECO. In the original filing of this annual report on Form 10-K, part of a paragraph was inadvertently omitted from the top of page 58. This amendment to the annual report on Form 10-K includes the originally omitted partial paragraph, changes references from “Form 10-K” to “Form 10-K/A,” provides new Chief Executive Officer and Chief Financial Officer certifications in place of the original certifications (HEI Exhibits 31.1, 31.2, 32.1 and 32.2 and HECO Exhibits 31.3, 31.4, 32.3 and 32.4) and provides new independent auditors’ reports and consents in place of the original reports and consents.

TABLE OF CONTENTS


		Page
Glossary of Terms		ii
Forward-Looking Statements and Risk Factors		vi

PART I

Item 1.	Business	1
Item 2.	Properties	44
Item 3.	Legal Proceedings	45
Item 4.	Submission of Matters to a Vote of Security Holders	46
Executive Officers of the Registrant (Hawaiian Electric Industries, Inc.)		46

PART II

Item 5.	Market for Registrants’ Common Equity and Related Stockholder Matters	47
Item 6.	Selected Financial Data	48
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	50
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	68
Item 8.	Financial Statements and Supplementary Data	68
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	68
Item 9A.	Controls and Procedures	68

PART III

Item 10.	Directors and Executive Officers of the Registrants	69
Item 11.	Executive Compensation	73
Item 12.	Security Ownership of Certain Beneficial Owners and Management	77
Item 13.	Certain Relationships and Related Transactions	78
Item 14.	Principal Accounting Fees and Services	78

PART IV

Item 15.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K	79
Independent Auditors’ Report - Hawaiian Electric Industries, Inc.		81
Independent Auditors’ Report - Hawaiian Electric Company, Inc.		82
Index to Exhibits		87
Signatures		115

GLOSSARY OF TERMS

Defined below are certain terms used in this report:


Terms		Definitions

1935 Act		Public Utility Holding Company Act of 1935

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

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

BIF		Bank Insurance Fund

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

Btu		British thermal unit

CDUP		Conservation District Use Permit

CERCLA		Comprehensive Environmental Response, Compensation and Liability Act

Chevron		Chevron Products Company, a fuel oil supplier

Company		When used in Hawaiian Electric Industries, Inc. sections, the “Company” refers to Hawaiian Electric Industries, Inc. and its direct and indirect subsidiaries, including, without limitation, Hawaiian Electric Company, Inc., Maui Electric Company, Limited, Hawaii Electric Light Company, Inc., HECO Capital Trust I, HECO Capital Trust II, 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, Hawaiian Electric Industries Capital Trust II, Hawaiian Electric Industries Capital Trust III, HEI Preferred Funding, LP, The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.), HEI Power Corp. and its subsidiaries and Malama Pacific Corp. When used in Hawaiian Electric Company, Inc. sections, the “Company” refers to Hawaiian Electric Company, Inc. and its direct subsidiaries, including, without limitation, Maui Electric Company, Limited, Hawaii Electric Light Company, Inc., HECO Capital Trust I, HECO Capital Trust II, HECO Capital Trust III and Renewable Hawaii, Inc.

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

CT		Combustion turbine

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

D&O		Decision and order

DOD		Department of Defense – federal

DOH		Department of Health of the State of Hawaii

DSM		Demand-side management

DTCC		Dual-train combined-cycle

EAPRC		East Asia Power Resources Corporation

ECA		Energy cost adjustment

Enserch		Enserch Development Corporation

EPA		Environmental Protection Agency – federal

GLOSSARY OF TERMS (continued)


Terms		Definitions

ERL		Environmental Response Law of the State of Hawaii

FDIC		Federal Deposit Insurance Corporation

FDICIA		Federal Deposit Insurance Corporation Improvement Act of 1991

federal		U.S. Government

FHLB		Federal Home Loan Bank

FICO		Financing Corporation

FIRREA		Financial Institutions Reform, Recovery, and Enforcement Act of 1989

Hamakua Partners		Hamakua Energy Partners, L.P., formerly known as Encogen Hawaii, L.P.

HRD		Hawi Renewable Development, Inc.

HCPC		Hilo Coast Power Company, formerly Hilo Coast Processing Company

HC&S		Hawaiian Commercial & Sugar Company, a division of A&B-Hawaii, Inc.

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

HECO’s Consolidated Financial Statements		Hawaiian Electric Company, Inc.’s Consolidated Financial Statements incorporated into Parts I, II and IV of this Form 10-K/A, which is filed as HECO Exhibit 99.4 and incorporated into this Form 10-K/A by reference

HECO’s MD&A		Hawaiian Electric Company, Inc.’s Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 50 to 67 of this Form 10-K/A

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

HEI’s Annual Report		Hawaiian Electric Industries, Inc.’s 2003 Annual Report to Shareholders, which is filed as HEI Exhibit 13 and incorporated into this Form 10-K/A by reference

HEI’s Consolidated Financial Statements		Hawaiian Electric Industries, Inc.’s Consolidated Financial Statements incorporated into Parts I, II and IV of this Form 10-K/A by reference to pages 39 to 88 of HEI’s Annual Report

HEI’s MD&A		Hawaiian Electric Industries, Inc.’s Management’s Discussion and Analysis of Financial Condition and Results of Operations incorporated into Parts I, II and IV of this Form 10-K/A by reference to pages 4 to 35 of HEI’s Annual Report

HEI’s 2004 Proxy Statement		Portions of Hawaiian Electric Industries, Inc.’s 2004 Proxy Statement dated March 9, 2004, which portions are incorporated into this Form 10-K/A by reference

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

iii

GLOSSARY OF TERMS (continued)


Terms		Definitions

HEIII		HEI Investments, Inc. (formerly HEI Investment Corp.), a wholly-owned 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. On October 23, 2001, the HEI Board of Directors adopted a formal plan to exit the international power business (engaged in by HEIPC and its subsidiaries).

HEIPC Group		HEI Power Corp. and its subsidiaries

HEIPI		HEI Properties, Inc., a wholly-owned subsidiary of Hawaiian Electric Industries, Inc.

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

HITI		Hawaiian Interisland Towing, Inc.

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

IPP		Independent power producer

IRP		Integrated resource plan

Kalaeloa		Kalaeloa Partners, L.P.

KCP		Kawaihae Cogeneration Partners

KDC		Keahole Defense Coalition

kV		kilovolt

KIP		Kalaeloa Investment Partners

KPP		Kahua Power Partners LLC

KWH		Kilowatthour

LSFO		Low sulfur fuel oil

MBtu		Million British thermal unit

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

MPC		Malama Pacific Corp., a wholly-owned subsidiary of Hawaiian Electric Industries, Inc. On September 14, 1998, the HEI Board of Directors adopted a plan to exit the residential real estate development business engaged in by Malama Pacific Corp. and its then-existing subsidiaries. As of December 31, 2003, all of its subsidiaries had been dissolved.

MSFO		Medium sulfur fuel oil

MW		Megawatts

NA		Not applicable

NM		Not meaningful

NOV		Notice of Violation

OPA		Federal Oil Pollution Act of 1990

OTS		Office of Thrift Supervision, Department of Treasury

PCB		Polychlorinated biphenyls

GLOSSARY OF TERMS (continued)


Terms		Definitions

PECS		Pacific Energy Conservation Services, Inc., a wholly-owned subsidiary of Hawaiian Electric Industries, Inc.

PGV		Puna Geothermal Venture

PPA		Power purchase agreement

PSD permit		Prevention of Significant Deterioration/Covered Source permit

PUC		Public Utilities Commission of the State of Hawaii

PURPA		Public Utility Regulatory Policies Act of 1978

QF		Qualifying Facility under the Public Utility Regulatory Policies Act of 1978

QTL		Qualified Thrift Lender

RCRA		Resource Conservation and Recovery Act of 1976

Registrant		Hawaiian Electric Industries, Inc. or Hawaiian Electric Company, Inc.

ROACE		Return on average common equity

SAIF		Savings Association Insurance Fund

SEC		Securities and Exchange Commission

ST		Steam turbine

state		State of Hawaii

Tesoro		Tesoro Hawaii Corp. dba BHP Petroleum Americas Refining Inc., a fuel oil supplier

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.

UIC		Underground Injection Control

UST		Underground storage tank

VIE		Variable interest entities

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

Forward-Looking Statements and Risk Factors

This report and other presentations made by Hawaiian Electric Industries, Inc. (HEI) and Hawaiian Electric Company, Inc. (HECO) and their subsidiaries contain “forward-looking statements,” which include statements that are predictive in nature, depend upon or refer to future events or conditions, and usually include words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “predicts,” “estimates” or similar expressions. In addition, any statements concerning future financial performance (including future revenues, expenses, earnings or losses or growth rates), ongoing business strategies or prospects and possible future actions, which may be provided by management, are also forward-looking statements. Forward-looking statements are based on current expectations and projections about future events and are subject to risks, uncertainties and 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. housing markets, the military presence in Hawaii and the effects of the February 2004 strike in the Hawaii concrete industry;

•

the effects of weather and natural disasters;

•

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

•

the timing and extent of changes in interest rates;

•

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

•

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

•

demand for services and market acceptance risks;

•

increasing competition in the electric utility and banking industries;

•

capacity and supply constraints or difficulties;

•

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

•

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

•

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

•

new technological developments that could affect the operations and prospects of HEI’s subsidiaries (including HECO and its subsidiaries) or their competitors;

•

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

•

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

•

the effects of changes in accounting principles applicable to HEI, HECO and their subsidiaries, including 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 the ratings of the securities of HEI and HECO;

•

the results of financing efforts;

•

faster than expected loan prepayments that can cause an acceleration of the amortization of premiums on loans and investments and the impairment of mortgage servicing rights of American Savings Bank, F.S.B. (ASB);

•

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

•

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

•

the risks of suffering losses that are uninsured; and

•

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

Forward-looking statements speak only as of the date of the report, presentation or filing in which they are made. Except to the extent required by the federal securities laws, HEI and its subsidiaries undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

PART I

ITEM 1.

BUSINESS

HEI

HEI was incorporated in 1981 under the laws of the State of Hawaii and is a holding company with its principal subsidiaries engaged in the electric utility, banking and other businesses operating primarily in the State of Hawaii. HEI’s predecessor, HECO, was incorporated under the laws of the Kingdom of Hawaii (now the State of Hawaii) on October 13, 1891. As a result of a 1983 corporate reorganization, HECO became an HEI subsidiary and common shareholders of HECO became common shareholders of HEI.

HECO and its operating subsidiaries, Maui Electric Company, Limited (MECO) and Hawaii Electric Light Company, Inc. (HELCO), are regulated electric public utilities providing the only electric public utility service on the islands of Oahu, Maui, Lanai, Molokai and Hawaii, which islands collectively include approximately 93% of Hawaii’s electric public utility market. HECO also owns all the common securities of HECO Capital Trust I, HECO Capital Trust II and HECO Capital Trust III (Delaware statutory trusts), which were formed to effect the issuances of $50 million of 8.05% cumulative quarterly income preferred securities in March 1997 (expected to be redeemed in the first half of 2004), $50 million of 7.30% cumulative quarterly income preferred securities in December 1998 and an anticipated $50 million of cumulative quarterly income preferred securities in the first half of 2004 (the proceeds of which will be used to redeem the preferred securities issued by HECO Capital Trust I), respectively, for the benefit of HECO, MECO and HELCO. In December 2002, HECO formed a subsidiary, Renewable Hawaii, Inc., to invest in renewable energy projects.

Besides HECO and its subsidiaries, HEI also owns directly or indirectly the following subsidiaries: HEI Diversified, Inc. (HEIDI) (a holding company) and its subsidiary, ASB, and the subsidiaries of ASB; Pacific Energy Conservation Services, Inc. (PECS); ProVision Technologies, Inc. (sold in July 2003); HEI Properties, Inc. (HEIPI); HEI Leasing, Inc. (dissolved in October 2003); Hycap Management, Inc. and its subsidiary; Hawaiian Electric Industries Capital Trust I; Hawaiian Electric Industries Capital Trust II and III (formed in 1997 to be available for trust securities financings); HEI District Cooling, Inc. (dissolved in October 2003); The Old Oahu Tug Service, Inc. (TOOTS); HEI Power Corp. (HEIPC) and its subsidiaries (discontinued operations); and Malama Pacific Corp. (MPC) (discontinued operations).

ASB, acquired in 1988, was the third largest financial institution in the State of Hawaii based on total assets and had 68 retail branches as of December 31, 2003. ASB has subsidiaries involved in the sale and distribution of insurance products and advertising activities for ASB and its subsidiaries and a subsidiary, ASB Realty Corporation, which elects to be taxed as a real estate investment trust and holds assets (primarily loans and mortgage-related securities) of $1.8 billion (see Note 9 to HEI’s Consolidated Financial Statements).

HEIDI was also the parent company of HEIDI Real Estate Corp., which was formed in February 1998. In September 1999, HEIDI Real Estate Corp.’s name was changed to HEIPI, and HEIDI transferred ownership of HEIPI to HEI. HEIPI currently holds venture capital investments.

PECS was formed in 1994 and currently is a contract services company providing limited support services in Hawaii. ProVision Technologies, Inc., formed in October 1998 to sell, install, operate and maintain on-site power generation equipment and auxiliary appliances in Hawaii and the Pacific Rim, was sold in July 2003. HEI Leasing, Inc. was formed in February 2000 to own passive investments and real estate subject to leases, but was never active and was dissolved in October 2003. Hycap Management, Inc., including its subsidiary HEI Preferred Funding, LP (a limited partnership in which Hycap Management, Inc. is the sole general partner), and Hawaiian Electric Industries Capital Trust I (a Delaware statutory trust in which HEI owns all the common securities) were formed to effect the issuance of $100 million of 8.36% HEI-obligated trust preferred securities in 1997. HEI District Cooling, Inc. was formed in August 1998 to develop, build, own, lease, operate and/or maintain, either directly or indirectly, central chilled water cooling system facilities, and other energy related products and services for commercial and residential buildings, but was dissolved in October 2003.

In November 1999, Hawaiian Tug & Barge Corp. (HTB) sold substantially all of its operating assets and the stock of YB for a nominal gain, changed its name to TOOTS and ceased maritime freight transportation operations. TOOTS currently administers certain employee and retiree-related benefits programs and monitors matters related its former operations and the operations of its former subsidiary.

For information concerning a strike in the Hawaii concrete industry that has been ongoing since early February 2004 and is adversely affecting the construction industry and Hawaii economy generally, see the discussion under the caption “Overview and strategy” in HECO’s MD&A. If a prolonged strike significantly impacted the Hawaii economy, the operations of the electric utilities and bank could be adversely affected.

For information about the Company’s discontinued operations, see Note 13 to HEI’s Consolidated Financial Statements.

For financial information about the Company’s industry segments, see Note 2 to HEI’s Consolidated Financial Statements.

For additional information about the Company, see HEI’s MD&A, HEI’s “Quantitative and Qualitative Disclosures about Market Risk” and HEI’s Consolidated Financial Statements.

The Company’s website address is www.hei.com. HEI and HECO currently make available free of charge through this website their annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports (since 1994) as soon as reasonably practicable after such material is electronically filed with the SEC.

Electric utility

HECO and subsidiaries and service areas

HECO, MECO and HELCO are regulated operating electric public utilities engaged in the production, purchase, transmission, distribution and sale of electricity on the islands of Oahu; Maui, Lanai and Molokai; and Hawaii, respectively. HECO was incorporated under the laws of the Kingdom of Hawaii (now State of Hawaii) in 1891. HECO acquired MECO in 1968 and HELCO in 1970. In 2003, the electric utilities’ revenues and net income from continuing operations amounted to approximately 78% and 67%, respectively, of HEI’s consolidated amounts, compared to approximately 76% and 76% in 2002 and approximately 75% and 82% in 2001, respectively.

The islands of Oahu, Maui, Lanai, Molokai and Hawaii have a combined population currently estimated at 1,197,000, or approximately 95% of the population of the State of Hawaii, and comprise a service area of 5,766 square miles. The principal communities served include Honolulu (on Oahu), Wailuku and Kahului (on Maui) and Hilo and Kona (on Hawaii). The service areas also include numerous suburban communities, resorts, U.S. Armed Forces installations and agricultural operations.

The state has granted HECO, MECO and HELCO nonexclusive franchises, which authorize the utilities to construct, operate and maintain facilities over and under public streets and sidewalks. HECO’s franchise covers the City & County of Honolulu, MECO’s franchises cover the County of Maui and the County of Kalawao, and HELCO’s franchise covers the County of Hawaii. Each of these franchises will continue in effect for an indefinite period of time until forfeited, altered, amended or repealed.

For additional information about HECO, see HEI’s MD&A, HEI’s “Quantitative and Qualitative Disclosures about Market Risk” and HEI’s Consolidated Financial Statements and HECO’s MD&A, HECO’s “Quantitative and Qualitative Disclosures about Market Risk” and HECO’s Consolidated Financial Statements.

Sales of electricity

HECO, MECO and HELCO provide the only electric public utility service on the islands they serve. The following table sets forth the number of electric customer accounts as of December 31, 2003, 2002 and 2001 and electric sales revenues by company for each of the years then ended:


	2003			2002			2001
(dollars in thousands)	Customer accounts	Electric sales revenues		Customer accounts	Electric sales revenues		Customer accounts	Electric sales revenues
HECO	286,677	$	960,717	283,161	$	865,608	280,911	$	882,308
MECO	61,423		213,806	59,983		191,029	58,840		203,847
HELCO	68,893		213,268	66,411		191,589	65,241		193,209

	416,993	$	1,387,791	409,555	$	1,248,226	404,992	$	1,279,364

Revenues from the sale of electricity in 2003 were from the following types of customers in the proportions shown:


	HECO		MECO		HELCO		Total
Residential	32	%	36	%	41	%	34	%
Commercial	32		35		41		34
Large light and power	35		29		18		31
Other	1		—		—		1

	100	%	100	%	100	%	100	%

HECO and its subsidiaries sales are not as strongly seasonal as compared to some utilities on the mainland. The weather in Hawaii is temperate, and has neither the cold winters nor the hot humid summers experienced in some parts of the mainland. Any seasonal variation in HECO and its subsidiaries sales is due largely to weather, with warm summers causing an increase in cooling demand. Hawaii’s economic activity throughout the year is relatively steady, although, generally, the summer months (June through August) and the winter months (December, January and February) see the most visitors to the islands, and result in an increase in demand for electricity.

HECO and its subsidiaries derived approximately 10%, 9% and 10% of their operating revenues from the sale of electricity to various federal government agencies in 2003, 2002 and 2001, respectively.

Formerly one of HECO’s larger customers, the Naval Base at Barbers Point, Oahu, closed in 1999 with redevelopment of the base to occur through 2020. Considering (1) that the base closure necessitated relocation of essential flight operations and support personnel to another base on Oahu and (2) the Naval Air Station Barbers Point Community Redevelopment Plan will increase development of the area, HECO continues to expect that the closure is likely to result in an overall increase in demand for electricity over time.

In 1995, HECO and the U.S. General Services Administration (GSA) entered into a Basic Ordering Agreement (GSA-BOA) under which HECO would arrange for the financing and installation of energy conservation projects at federal facilities in Hawaii. In 1996, HECO signed an umbrella Basic Ordering Agreement with the Department of Defense (DOD-BOA) and in 2001, a new DOD-BOA was signed. In 1997, HECO and the U.S. Postal Service signed a Shared Energy Savings Contract. Under these and other agreements, HECO has completed energy conservation and other projects for federal agencies over the years.

Executive Order 13123, adopted in 1994, mandates that each federal agency develop and implement a program to reduce energy consumption by 35% by the year 2010 to the extent that these measures are cost effective. The 35% reduction will be measured relative to the agency’s 1985 energy use. HECO continues to work with various federal agencies to implement demand-side management (DSM) programs that will help them achieve their energy reduction objectives. Neither HEI nor HECO management can predict with certainty the impact of Executive Order 13123 on HEI’s or HECO’s future financial condition, results of operations or liquidity.

Selected consolidated electric utility operating statistics


	2003		2002		2001		2000		1999
KWH sales (millions)
Residential		2,875.9		2,778.5		2,665.2		2,627.2		2,550.5
Commercial		3,168.3		3,073.6		3,016.1		2,923.5		2,781.5
Large light and power		3,676.5		3,639.2		3,636.5		3,666.9		3,598.3
Other		54.4		53.0		52.6		54.1		54.7

		9,775.1		9,544.3		9,370.4		9,271.7		8,985.0


KWH net generated and purchased (millions)
Net generated		6,280.2		6,249.7		6,042.4		6,247.0		6,115.1
Purchased		4,054.3		3,829.6		3,861.6		3,572.0		3,391.7

		10,334.5		10,079.3		9,904.0		9,819.0		9,506.8

Losses and system uses (%)		5.2		5.1		5.2		5.4		5.3

Energy supply (year-end)
Net generating capability—MW		1,606		1,606		1,608		1,608		1,587
Firm purchased capability—MW		531		510		531		532		472

		2,137		2,116		2,139		2,140		2,059

Net peak demand—MW ¹		1,638		1,583		1,564		1,527		1,478
Btu per net KWH generated		10,663		10,673		10,675		10,818		10,789
Average fuel oil cost per Mbtu (cents)		580.5		466.4		539.3		538.5		329.7

Customer accounts (year-end)
Residential		362,400		356,244		352,132		347,316		342,957
Commercial		52,659		51,386		50,974		50,434		49,549
Large light and power		549		551		542		547		550
Other		1,385		1,374		1,344		1,342		1,299

		416,993		409,555		404,992		399,639		394,355


Electric revenues (thousands)
Residential	$	471,697	$	426,291	$	425,287	$	421,129	$	356,631
Commercial		474,017		425,595		436,751		422,977		345,808
Large light and power		434,319		389,312		409,977		414,067		336,434
Other		7,758		7,028		7,349		7,487		6,454

	$	1,387,791	$	1,248,226	$	1,279,364	$	1,265,660	$	1,045,327


Average revenue per KWH sold (cents)
Residential		16.40		15.34		15.96		16.03		13.98
Commercial		14.96		13.85		14.48		14.47		12.43
Large light and power		11.81		10.70		11.27		11.29		9.35
Other		14.26		13.26		13.98		13.84		11.80
Average revenue per KWH sold		14.20		13.08		13.65		13.65		11.63

Residential statistics
Average annual use per customer account (KWH)		8,004		7,840		7,620		7,618		7,490
Average annual revenue per customer account	$	1,313	$	1,203	$	1,216	$	1,221	$	1,047
Average number of customer accounts		359,288		354,419		349,782		344,882		340,528

¹	Sum of the net peak demands on all islands served, noncoincident and nonintegrated.

Generation statistics

The following table contains certain generation statistics as of December 31, 2003 and for the year ended December 31, 2003. The capability available for operation at any given time may be more or less than the generating capability shown because of capability restrictions or temporary outages for inspection, maintenance, repairs or unforeseen circumstances.


	Island of Oahu- HECO		Island of Maui- MECO		Island of Lanai- MECO		Island of Molokai- MECO		Island of Hawaii- HELCO		Total
Net generating and firm purchased capability (MW) at December 31, 2003¹
Conventional oil-fired steam units	1,106.8		35.9		—		—		62.2		1,204.9
Diesel	—		94.9		10.3		9.6		39.0		153.8
Combustion turbines (peaking units)	101.8		—		—		—		—		101.8
Combustion turbines	—		41.6		—		2.2		44.9		88.7
Combined-cycle unit	—		56.8		—		—		—		56.8
Firm contract power²	406.0		16.0		—		—		109.0		531.0

	1,614.6		245.2		10.3		11.8		255.1		2,137.0

Net peak demand (MW)	1,242.0		197.7		5.0		6.5		186.7		1,637.9³
Reserve margin	30.5	%	24.0	%	105.8	%	82.2	%	36.6	%	30.9	%
Annual load factor	72.7	%	70.2	%	67.6	%	69.6	%	69.8	%	72.0	%³
KWH net generated and purchased (millions)	7,909.0		1,215.4		29.6		39.6		1,140.9		10,334.5

¹	HECO units at normal ratings; MECO and HELCO units at reserve ratings.

Nonutility generators—HECO: 180 MW (Kalaeloa Partners, L.P., oil-fired), 180 MW (AES Hawaii, Inc., coal-fired) and 46 MW (H-Power, refuse-fired); MECO: 16 MW (Hawaiian Commercial & Sugar Company, primarily bagasse-fired); HELCO: 27 MW (Puna Geothermal Venture, geothermal), 22 MW (Hilo Coast Power Company, coal-fired) and 60 MW (Hamakua Energy Partners, L.P., oil-fired).

³	Noncoincident and nonintegrated.

Generating reliability

HECO, HELCO and MECO have isolated electrical systems that are not interconnected to each other or to any other electrical grid. HECO serves the island of Oahu and HELCO serves the island of Hawaii. MECO has three separate electrical systems—one each on the islands of Maui, Molokai and Lanai.

Because each island system cannot rely upon backup generation from neighboring utilities, HECO, HELCO and MECO each maintain a higher level of reserve generation than is typically carried by interconnected mainland utilities, which are able to share reserve capacity. These higher levels of reserve margins are required to meet peak electric demands, to provide for scheduled maintenance of generating units (including the units operated by independent power producers (IPPs) relied upon for firm capacity) and to allow for the forced outage of the largest generating unit in the system. Although the planning for, and installation of, adequate levels of reserve generation have contributed to the achievement of generally high levels of system reliability, service interruptions do occur from time to time as a result of unforeseen circumstances. For example, HECO implemented load shedding and temporarily shut off power to a significant number of customers on one occasion in 2002, due to unplanned generating unit outages. Load shedding is a predetermined plan that prevents overloading and possible major damage to generating units and potentially a much larger power outage.

HELCO’s management is concerned about the possibility of power interruptions as a result of the current operating status of various IPPs supplying power to it and the condition and performance of aging generators on the

HELCO system that were intended to be operated less frequently once CT-4 and CT-5 were installed at HELCO’s Keahole power plant. (See discussion in Note 11 to HECO’s Consolidated Financial Statements). A significant number of HELCO’s customers experienced rolling blackouts on two occasions in 2002 due to unplanned generating unit outages.

Integrated resource planning and requirements for additional generating capacity

As a result of a proceeding initiated in 1990, the Public Utilities Commission of the State of Hawaii (PUC) issued an order in 1992 requiring the energy utilities in Hawaii to develop integrated resource plans (IRPs). The goal of integrated resource planning is the identification of demand- and supply-side resources and the integration of these resources for meeting near- and long-term consumer energy needs in an efficient and reliable manner at the lowest reasonable cost. In its 1992 order, the PUC adopted a “framework,” which established both the process and the guidelines for developing IRPs. The PUC’s framework directs that each plan cover a 20-year planning horizon with a five-year program implementation schedule and states that the planning cycle will be repeated every three years. Under the framework, the PUC may approve, reject or require modifications of the utilities’ IRPs.

The framework also states that utilities are entitled to recover all appropriate and reasonable integrated resource planning and implementation costs, including the costs of planning and implementing DSM programs. Under appropriate circumstances, the utilities have been allowed in the past to recover lost margins resulting from DSM programs and earn shareholder incentives. The PUC has approved IRP cost recovery provisions for HECO, MECO and HELCO. Pursuant to the cost recovery provisions, the electric utilities have been allowed to recover through a surcharge the costs for approved DSM programs (including DSM program lost margins and shareholder incentives), and other incremental IRP costs incurred by the utilities and approved by the PUC, to the extent the costs are not included in their base rates.

In October 2001, HECO and the Consumer Advocate finalized agreements, which were approved by the PUC in November 2001, under which HECO’s three commercial and industrial DSM programs and two residential DSM programs would be continued until HECO’s next rate case, which, under the agreements, HECO committed to file using a 2003 or 2004 test year and following the PUC’s rules for determining the test year. In August 2003, HECO and the Consumer Advocate agreed, and the PUC approved, a delay in the filing of HECO’s next rate case, with the result that the rate case would be filed using a 2005 test year. 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. HECO also agreed it will not pursue the continuation of lost margins recovery and shareholder incentives through a surcharge mechanism in future rate cases. Consistent with the HECO agreements, in October 2001, MECO and HELCO reached agreements with the Consumer Advocate and filed requests to continue their four existing DSM programs. In November 2001, the PUC issued orders (one of which was later amended) that, subject to certain reporting requirements and other conditions, allowed MECO and HELCO to continue temporarily their respective four existing energy efficiency DSM programs. See “Other regulatory matters—Demand-side management programs—agreements with the Consumer Advocate” at page 55 in HECO’s MD&A. All of the electric utilities’ existing DSM programs are energy efficiency programs designed to reduce the consumption of electricity.

In August 2000, pursuant to a stipulation filed by the electric utilities and the parties in the IRP cost proceedings, the PUC issued an order allowing the electric utilities to begin recovering the 1995 through 1999 incremental IRP costs, subject to refund with interest, pending the PUC’s final decision and order (D&O) approving recovery of each respective year’s incremental IRP costs. Procedural schedules for the IRP cost proceedings have been established with respect to the 2000-2003 IRP costs, such that the electric utilities can begin recovering incremental IRP costs in the month after the filing of the actual costs incurred for the year, subject to refund with interest, pending the PUC’s final D&O approving recovery of the costs. The Consumer Advocate has objected to the recovery of $2.5 million (before interest) of the $10.3 million of incremental IRP costs incurred during the 1995-2002 period, and the PUC’s decision is pending on this matter.

The electric utilities have completed the recovery of their respective 1995 through 2001 incremental IRP costs through a surcharge on customer bills, subject to refund with interest. In addition, HECO completed the recovery of its 2002 incremental IRP costs in May 2003, subject to refund with interest. MECO is scheduled to complete the recovery of its 2002 incremental IRP costs by May 2004. As of December 31, 2003, the amount of revenues the electric utilities recorded for IRP cost recoveries, subject to refund with interest, amounted to $17 million. HECO

and MECO expect to begin recovering their incremental 2003 IRP costs, subject to refund with interest pending a final D&O, following the filing of actual 2003 costs (which is expected to occur in late March or early April 2004).

In early 2001, the PUC issued its final D&O in the HELCO 2000 test year rate case, in which the PUC concluded that it is appropriate for HELCO to recover its IRP costs through base rates (and included an estimated amount for such costs in HELCO’s test year revenue requirements) and to discontinue recovery of incremental IRP costs through the separate surcharge. HELCO recovered its incremental IRP costs incurred in 2000, which were incurred prior to the final D&O in its rate case, through its surcharge. HELCO’s IRP costs incurred for 2001 and future years are recovered through HELCO’s base rates. HELCO will continue to recover its DSM program costs, lost margins and shareholder incentives approved by the PUC in a separate surcharge.

The utilities have characterized their proposed IRPs as planning strategies, rather than fixed courses of action, and the resources ultimately added to their systems may differ from those included in their 20-year plans. Under the IRP framework, the utilities are required to submit annual evaluations of their plans (including a revised five-year program implementation schedule) and to submit new plans on a three-year cycle, subject to changes approved by the PUC. Prior to proceeding with the DSM programs, separate PUC approval proceedings must be completed, in which the PUC further reviews the details of the proposed programs and the utilities’ proposals for the recovery of DSM program expenditures, lost margins and shareholder incentives.

HECO’s IRP. HECO filed its second IRP with the PUC in January 1998 and updated the status of its DSM and Supply Side Action Plans in July 1999. In January 2001, the parties to the proceeding filed a stipulation for PUC approval to expedite the proceeding and the PUC approved the stipulation, closed the docket and ordered HECO to submit its IRP annual evaluation report and program implementation schedule by October 2002 (subsequently extended to December 2002) and its third IRP by October 2005, as stipulated. The PUC also ordered HECO to immediately notify it in writing if HECO requires additional generation prior to the 2009 time frame.

In December 2002, HECO filed with the PUC its IRP evaluation report, updating the second IRP to reflect the latest sales and fuel forecasts and updated key planning assumptions.

On the supply side, HECO’s updated second IRP focused on the planning for the next generating unit addition in the 2009 time frame—a 107 MW simple-cycle combustion turbine. The updated second IRP also includes plans to add a second 107 MW simple-cycle combustion turbine in 2015, and in 2016, a conversion unit 105 MW steam turbine to create a dual-train combined-cycle unit. However, the report notes there is flexibility to allow HECO to defer the need for the second and third generating units should alternative generation technologies advance to where they are an economically and technically feasible substitutes for conventional generation. In addition, pursuant to HECO’s generation asset management program, all existing generating units are currently planned to be operated (future environmental considerations permitting) beyond the 20-year IRP planning period (1998-2017).

On the demand side, in November 2001, the PUC issued two D&Os allowing HECO to temporarily continue its five energy efficiency DSM programs until its next rate case. The five energy efficiency DSM programs are designed to reduce the rate of increase in Oahu’s energy use, defer construction of new generating units, minimize the state’s use of oil, and achieve savings for utility customers who participate in the programs. The energy efficiency DSM programs include incentives for customers to install efficient lighting, refrigeration, water-heating and air-conditioning equipment and industrial motors. HECO’s updated second IRP includes two load management programs scheduled for implementation in 2004 (i.e., a Residential Direct Load Control Program and a Commercial and Industrial Direct Load Control Program). HECO filed applications with the PUC requesting approval of these two load management programs in June and December 2003, respectively.

In September 2003, the PUC opened a docket to commence HECO’s third IRP, which HECO expects to file by March 2005 and expects will require multiple solutions to meet Oahu’s future energy needs, including renewable energy resources, energy efficiency, conservation, technology (such as CHP) and central station generation. Given the lead times needed for permitting and regulatory approvals, in October 2003, HECO submitted a covered source permit application with the DOH for a 107 MW simple cycle combustion turbine in Campbell Industrial Park. The application specifies that the unit would use diesel fuel oil or naphtha, with the ability to convert to a bio-fuel, like ethanol or bio-diesel, when it becomes commercially practicable.

MECO’s IRP. MECO filed its second IRP with the PUC in May 2000. A stipulated prehearing order was approved by the PUC in October 2000. The parties filed individual Statements of Position in May 2001. In February 2004, the parties to the proceeding filed a stipulation for PUC approval to expedite the proceeding, close the docket, and establish a schedule for MECO’s next IRP annual evaluation report and program implementation schedule and its next IRP. The stipulation provided that MECO would submit IRP evaluation reports and program implementation schedules by April 2004 and April 2005 and its next (third) IRP by October 2006. The PUC’s decision on the stipulation is pending.

MECO’s second IRP 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, 100 MW at its new Waena site in increments from 2007-2018, beginning with a 20 MW combustion turbine in 2007, and 10 MW from the acquisition of a wind resource in 2003 (currently, MECO expects to receive 20 MW of wind energy in 2006). Approximately 4 MW of additional generation through the year 2020 is planned for each of the islands of Lanai and Molokai. MECO completed the installation of a 20 MW increment (the second) at Maalaea in September 2000, and the final increment of 18 MW, which was originally expected to be installed in 2005, is currently expected to be installed in September 2006 (assuming receipt in early 2004 of the necessary air permit, for which an application was submitted in December 2001).

On the demand side, in November 2001 the PUC issued a D&O allowing MECO to continue temporarily its four existing energy efficiency DSM programs, which are similar in design to HECO’s programs. MECO’s IRP included plans for a new energy efficiency DSM program and two new load management DSM programs. MECO does not plan to proceed with a new energy efficiency DSM program at this time, and MECO is in the process of evaluating the load management DSM programs, and will determine at a later date the need for and timing of filing load management DSM program applications.

HELCO’s IRP. In September 1998, HELCO filed with the PUC its second IRP, which was updated in March 1999 and revised in June 1999. A schedule for the proceeding was approved by the PUC, and the parties to the proceeding completed two rounds of discovery. In January 2004, the parties to the proceeding filed a stipulation for PUC approval to expedite the proceeding and in February 2004 the PUC approved the stipulation, closed the docket and ordered HELCO to submit its IRP annual evaluation report by the end of March 2004 and its next IRP by October 2005, as stipulated. The PUC also ordered HELCO to immediately notify it in writing should circumstances change pertaining to, among other things, HELCO’s supply-side resources and load and sales forecast. The PUC subsequently opened a docket to commence HELCO’s third IRP.

The second IRP identified changes in key forecasts and assumptions since the development of HELCO’s initial IRP. On the supply side, HELCO’s second IRP focused on the planning for generating unit additions after near-term additions. Due to delays in adding new generation, the near-term additions proposed in HELCO’s second IRP included installing two 20 MW combustion turbines (CTs) at its Keahole power plant site and proceeding in parallel with a power purchase agreement (PPA) with Hamakua Energy Partners, L.P. (Hamakua Partners, formerly Encogen Hawaii, L.P.) for a 60 MW (net) dual-train combined-cycle (DTCC) facility.

The Hamakua Partners PPA was approved in 1999 and its DTCC facility was completed in December 2000. (See the discussion of HELCO power purchase agreements in “Nonutility generation.”) The two Keahole CTs, CT-4 and CT-5, which were the first two phases of a planned 56 MW (net) DTCC unit, have been delayed, but are now expected to be fully operational by December 31, 2004. (See “HELCO power situation” in Note 11 to HECO’s Consolidated Financial Statements.) A PPA with Hilo Coast Power Company (HCPC) for 18 MW of firm capacity terminated at the end of 1999, but as a result of the delays in adding new generation, HELCO has been purchasing 22 MW of firm capacity from HCPC’s coal-fired facility under a restated and amended PPA, the term of which runs through 2004, but automatically extends for one-year periods thereafter, unless terminated prior to an extension period by either party. HELCO also has deferred the retirements of some of its older generating units. After CT-4 and CT-5 are installed, HELCO’s current plans are to install a 16 MW steam turbine, ST-7, in 2009 or earlier pending approval of land use re-classification, zoning approval and obtaining all the necessary permits and approvals to complete the DTCC unit. After the installation of ST-7, the target date for the next firm capacity

addition is the 2017 timeframe. The timing of the need for additional new generation may change, however, based on factors such as the condition of the units whose retirements have been deferred, and the status of the nonutility generators providing firm capacity, including Puna Geothermal Venture (PGV) and HCPC. (See the discussion of HELCO power purchase agreements in “Nonutility generation.”)

On the demand side, in December 2001 the PUC issued a D&O allowing HELCO to continue temporarily its four existing energy efficiency DSM programs, which are similar in design to HECO’s programs.

New capital projects

The capital projects of the electric utilities may be subject to various approval and permitting processes, including obtaining PUC approval of the project, air permits from the Department of Health of the State of Hawaii (DOH) and/or the U.S. Environmental Protection Agency (EPA) and land use permits from the Hawaii Board of Land and Natural Resources (BLNR). Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits could result in project delays, increased project costs and/or project abandonments. Extensive project delays and significantly increased project costs could result in a portion of the project costs being excluded from rates. If a project is abandoned, the project costs are generally written-off to expense, unless the PUC determines that all or part of the costs may be deferred for later recovery in rates.

In addition to HELCO’s Keahole power plant expansion project and HECO’s East Oahu Transmission Project (see discussion in Note 11 to HECO’s Consolidated Financial Statements), the Company has two other significant capital projects currently in progress. In 2003, construction commenced on a $37 million project for an underground fuel pipeline that will transport fuel from an oil refinery at Campbell Industrial Park to HECO’s Waiau power plant. This project is scheduled for completion in late 2004. Also in 2003, planning continued on HECO’s $23 million project to construct a New Dispatch Center which will house a modernized Energy Management System, and which will be integrated with new Outage Management and Customer Information systems. The New Dispatch Center project is expected to be completed in 2007, with the Energy Management System operational in 2006.

Nonutility generation

The Company has supported state and federal energy policies which encourage the development of alternate energy sources that reduce the use of fuel oil. The Company’s alternate energy sources range from wind, geothermal and hydroelectric power, to energy produced by the burning of bagasse (sugarcane waste) and municipal waste and coal.

HECO PPAs. HECO currently has three major PPAs. In March 1988, HECO entered into a PPA with AES Barbers Point, Inc. (now known as AES Hawaii, Inc. (AES Hawaii)), a Hawaii-based, indirect subsidiary of The AES Corporation. The agreement with AES Hawaii, as amended in August 1989, provides that, for a period of 30 years beginning September 1992, HECO will purchase 180 MW of firm capacity. The AES Hawaii 180 MW coal-fired cogeneration plant, which became operational in September 1992, utilizes a “clean coal” technology. The facility is designed to sell sufficient steam to be a “Qualifying Facility” (QF) under the Public Utility Regulatory Policies Act of 1978 (PURPA). See discussion of a lawsuit against The AES Corporation, AES Hawaii, HECO and HEI in Note 11 to HECO’s Consolidated Financial Statements. Under the amended PPA, AES Hawaii must obtain certain consents from HECO prior to entering into any arrangement to refinance the facility. In the second quarter of 2003, HECO and AES Hawaii reached agreement on the terms upon which HECO would consent to a proposed refinancing. Under the agreement, which was contingent on obtaining certain PUC approvals and completion of the refinancing, HECO received consideration for its consent, primarily in the form of a PPA amendment that reduces the cost of firm capacity supplied to HECO pursuant to the PPA, retroactive to June 1, 2003. The benefit of the firm capacity cost reduction, totaling approximately $2.9 million annually for the remaining term of the PPA, is being passed on to ratepayers through a reduction in rates. AES Hawaii also has granted HECO an option, subject to certain conditions, to acquire an interest in portions of the AES Hawaii facility site that are not needed for the existing plant operations, and which potentially could be used for the development of another coal-fired facility. On July 1, 2003, the PUC issued a D&O approving the PPA amendment and the establishment of a rate adjustment (lowering rates) on short notice, and, on July 9, 2003, the PUC issued a D&O clarifying its July 1, 2003 D&O. On July 31, 2003, the proposed refinancing was completed and capacity payments were reduced, retroactive to June 1, 2003.

In October 1988, HECO entered into an agreement with Kalaeloa Partners, L.P. (Kalaeloa), a limited partnership whose sole general partner was an indirect, wholly-owned subsidiary of ASEA Brown Boveri, Inc. (ABB), which has

guaranteed certain of Kalaeloa’s obligations and, through affiliates, contracted to design, build, operate and maintain the facility. The agreement with Kalaeloa, as amended, provides that HECO will purchase 180 MW of firm capacity for a period of 25 years beginning in May 1991. The Kalaeloa facility, which was completed in the second quarter of 1991, is a combined-cycle operation, consisting of two oil-fired combustion turbines burning low sulfur fuel oil (LSFO) and a steam turbine that utilizes waste heat from the combustion turbines. The facility is designed to sell sufficient steam to be a QF. As of February 28, 1997, the ownership of Kalaeloa was restructured so that 1% was owned by the ABB subsidiary as the general partner and 99% was owned by Kalaeloa Investment Partners (KIP) as the limited partner. KIP is a limited partnership comprised of PSEG Hawaiian Management, Inc. and PSEG Hawaiian Investment, Inc. (nonregulated affiliates of Public Service Enterprise Group Incorporated) and Harbert Power Corporation. Subsequently, HECO consented to, and the PUC approved of, the transfer of the general partner partnership interest from the ABB subsidiary to an entity affiliated with the owners of KIP. During the second quarter of 2003, Kalaeloa approached HECO with plans to upgrade the combustion turbines (the M upgrade) by installing new parts designed to improve their efficiency and output. The upgraded combustion turbines would allow Kalaeloa to increase the capacity of the facility by approximately 20 MW. Under the agreement, Kalaeloa may not make any modifications to the facility that would either increase or decrease the generating capacity of the facility without the prior approval of HECO, except as required by law or regulation. The agreement also provides that HECO shall not be obligated to approve a change in facility capacity if such change would adversely impact HECO system reliability or result in an increased cost of power to HECO from the facility. On December 31, 2003, HECO and Kalaeloa entered into a Consent and Agreement (Consent) in which HECO consented to the M upgrade. The Consent provides that neither the M upgrade nor HECO’s consent to the M upgrade shall obligate HECO to accept additional energy made available as a result of the M upgrade, or to enter into negotiations to accept any change in the firm capacity of the facility, and shall not affect the rights of the parties under the section of the agreement related to an increase in firm capacity.

HECO also entered into a PPA in March 1986 and a firm capacity amendment in April 1991 with the City and County of Honolulu with respect to a refuse-fired plant (H-POWER). The H-POWER facility began to provide firm energy in 1990 and currently supplies HECO with 46 MW of firm capacity. The firm capacity amendment provides that HECO will purchase firm capacity until mid-2015.

HECO purchases energy on an as-available basis from two nonutility generators, which are diesel-fired qualifying cogeneration facilities at the two oil refineries (10 MW and 18 MW) on Oahu. HECO previously purchased energy on an as-available basis from an approximately 3 MW combustion turbine fired by methane gas from a landfill. In March 2002, the combustion turbine suffered a major failure. In July 2002, the owner of the facility requested that HECO terminate the PPA and HECO agreed.

The PUC has approved and allowed rate recovery for the firm capacity and purchased energy costs related to HECO’s three major PPAs that provide a total of 406 MW of firm capacity, representing 25% of HECO’s total net generating and firm purchased capacity on the island of Oahu as of December 31, 2003. The PUC also has approved and allowed rate recovery for the purchased energy costs related to HECO’s as-available energy PPAs.

MECO and HELCO PPAs. As of December 31, 2003, MECO and HELCO had PPAs for 16 MW (includes 4 MW of system protection) and 109 MW of currently available firm capacity, respectively.

MECO has a PPA with Hawaiian Commercial & Sugar Company (HC&S) for 16 MW of firm capacity. The HC&S generating units primarily burn bagasse (sugar cane waste) along with secondary fuels of oil or coal. In March 1998, an HC&S unit failed and HC&S lost 10 MW of generating capacity. HC&S replaced the unit and put it into operation in the second quarter of 2000. HC&S, however, has had some difficulties in meeting its contractual obligations to MECO for the years 2000 through 2003 due to operational constraints that led to several claims of force majeure by HC&S. The constraints have been primarily due to an extended drought condition on Maui that impacts HC&S’s irrigation pumping load for its sugar cane operations. There has also been a higher than normal reduction in energy produced due to other equipment outages. On January 23, 2001, MECO rescinded a December 27, 1999 PPA termination notice that it had sent to HC&S and agreed with HC&S that neither party would issue to the other a notice of termination prior to the end of 2002. On June 14, 2002, MECO and HC&S agreed that neither party will give written notice of termination under the terms of the PPA, such that the PPA terminates prior to December 31, 2007. As a result, the PPA remains in force and effect through December 31, 2007, and from year to year thereafter, subject to termination on or after December 31, 2007 on not less than two years prior written notice by either party.

HELCO has a 35-year PPA with Puna Geothermal Venture (PGV) for 30 MW of firm capacity from its geothermal steam facility expiring on December 31, 2027. PGV’s output was reduced to 6 MW from April 2002 to March 2003. The loss of generation was attributed to blockage of a source well due to a failed liner 5,000 feet below the earth’s surface and decreasing steam quality emanating from one of PGV’s source wells. PGV completed drilling an additional source well in February 2003, and converted the blocked source well into an injection well in early March 2003. The new injection well was tested and PGV’s capacity is currently between 25 to 28 MW. PGV obtained a permit from the DOH for the new injection well in March 2003. Without the new injection well, PGV was able to produce only about 10 to 11 MW due to the high moisture content of the steam from the new source well. PGV is assessing whether to drill another source well or to install new generation equipment designed to utilize the lower quality steam. While PGV indicates it is evaluating its options to enable it to restore its 30 MW commitment to HELCO as soon as possible, HELCO cannot predict when PGV will be able to meet its contractual commitment. HELCO’s PPA with PGV provides for annual availability sanctions against PGV if PGV does not provide up to the contracted 30 MW of capacity. In the first quarter ending March 31, 2003, HELCO recorded $0.7 million lower purchased power expense from PGV for availability sanctions for not meeting contracted capacity for 2002. In addition, since PGV had not yet restored its 30 MW commitment to HELCO by December 31, 2003, availability sanctions for 2003, of approximately $0.2 million, will be assessed against PGV in 2004. Constellation Energy, parent company of PGV, has solicited preliminary indications of interest from potential bidders in order to explore the possibility of putting PGV up for sale. HELCO is not aware if and when a sale will be completed.

On October 4, 1999, HELCO entered into a PPA with HCPC effective January 1, 2000 through December 31, 2004, subject to early termination by HELCO after two years, whereby HELCO purchases 22 MW of firm capacity from HCPC’s coal-fired facility. The PPA extends for one-year periods thereafter, unless terminated prior to an extension period. The PPA was amended on November 5, 1999, which extended the November 30, 1999 deadline for obtaining PUC approval of the PPA. The PUC approved the PPA, as amended, on December 7, 1999.

In October 1997, HELCO entered into an agreement with Encogen, a limited partnership whose general partners at the time were wholly-owned special-purpose subsidiaries of Enserch and Jones Capital Corporation. Enserch Corporation and J.A. Jones, Inc. (Jones), the parent companies of Enserch and Jones Capital Corporation, respectively, guaranteed certain of Encogen’s obligations. The agreement provides that HELCO will purchase up to 60 MW (net) of firm capacity for a period of 30 years. The DTCC facility, which primarily burns naphtha, consists of two oil-fired combustion turbines and a steam turbine that utilizes waste heat from the combustion turbines. The PUC approved the agreement on July 14, 1999. On November 8, 1999, HELCO entered into a PPA Novation with Encogen and Hamakua Partners, which recognizes the transfer of the obligations of Encogen under the PPA to Hamakua Partners. Hamakua Partners was formed as a result of the sale of the general partner and limited partner partnership interests of Enserch to entities affiliated with TECO Energy Inc., which is a Florida-based energy company and parent company of Tampa Electric Company, a regulated electric utility. TECO Energy Inc. has replaced the guarantee of Enserch Corporation of certain of Hamakua Partners’ obligations. On August 12, 2000, Hamakua Partners began providing HELCO with firm capacity from the first phase of a two-phase construction completion schedule. On December 31, 2000, Hamakua Partners began providing firm capacity from the entire facility, following completion of the second phase of construction. In June 2001, Hamakua Partners demonstrated 60 MW of output from the facility. Subsequently, the output deteriorated due to technical problems in the steam turbine. Hamakua Partners has since resolved its nozzle plugging problems, but due to high nitrogen oxide emissions and high steam turbine vibration problems, the output had been limited to 55-57 MW in early 2003. Hamakua Partners requested maintenance outages to correct the problems and returned to providing HELCO with 60 MW later in 2003. In September 2003, Jones filed for reorganization in bankruptcy in North Carolina. Jones is the parent company of the managing general partner and a limited partner of Hamakua Partners, and is one of the two co-guarantors of the Hamakua Partners project. Jones has stated that the bankruptcy filing will have no impact on Hamakua Partners’ ability to meet its contractual commitments. Jones has been attempting to sell its interest in Hamakua Partners under the supervision of the bankruptcy court. An auction among the qualified bidders was held on February 23, 2004 and the court held a hearing on February 24, 2004. By Order dated March 2, 2004, the court approved a motion to sell substantially all of the assets of Jones to United States Power Fund L. P. (USPF) and directed the appropriate parties to implement the sale. HELCO will be working with Jones and USPF to evaluate the terms and conditions of the sale and any implications of the sale on the PPA with Hamakua Partners.

HELCO purchases energy on an as-available basis from a number of nonutility generators. The largest include an 11 MW run-of-the-river hydroelectric facility and a 7 MW wind facility. Wailuku River Hydroelectric L.P., the owner of the hydroelectric facility, has an existing contract to provide HELCO with as-available power through May 2023. Apollo Energy Corporation (Apollo), the owner of the wind facility, has an existing contract to provide HELCO with as-available windpower through June 29, 2002 (and extending thereafter until terminated by HELCO or Apollo). Apollo filed a petition for hearing with the PUC on April 28, 2000, alleging that it had unsuccessfully attempted to negotiate a new power purchase agreement with HELCO. Apollo had offered to repower its existing 7 MW facility by the end of 2000 and to install additional wind turbines, up to a total allowed capacity of 15 MW, by the end of 2001. The parties agreed to limit to four issues the matters being presented to the PUC for guidance: whether Apollo is entitled to capacity payments; whether Apollo is entitled to a minimum purchase rate; whether certain performance standards should apply; and whether HELCO’s proposed dispute resolution provision should apply. A hearing on these issues was held on October 3 to 5, 2000. On May 30, 2001, the PUC issued a D&O in which it ordered HELCO and Apollo to continue to negotiate a PPA, consistent with the terms of the D&O, and to submit by August 13, 2001 either a finalized PPA or status reports informing the PUC of matters preventing finalization of a PPA. HELCO and Apollo were unable to agree to a PPA by August 13, 2001, and each submitted a status report. The parties continued to negotiate in 2002 and 2003, but final agreement has not been reached on certain technical and interconnection cost issues.

On August 17, 1999, HELCO entered into a PPA with Kahua Power Partners LLC (KPP) for the purchase of as-available energy from KPP’s proposed 10 MW windfarm. The PPA was amended by Amendment No. 1 dated April 4, 2000. The PUC approved the PPA, as amended, on June 1, 2001. KPP did not, however, construct its windfarm. GE Wind Energy completed the acquisition of certain assets of Enron Wind Corporation in May 2002, including the proposed KPP project. On October 7, 2003, GE Wind Energy assigned the KPP PPA to Hawi Renewable Development, Inc. (HRD). On December 9, 2003, HELCO terminated the KPP PPA pursuant to HRD’s notice that it does not plan to develop that wind farm, and its request that the PPA be terminated.

On January 8, 2001, HELCO entered into a PPA with HRD for the purchase of as-available energy from HRD’s proposed 5 MW windfarm. An amendment to the PPA was completed on April 30, 2002. The PPA, as amended, was approved by the PUC on January 14, 2003. Due to transmission line limitations, the output of HRD would have been limited to 3 MW if the KPP windfarm were connected to the electric grid through the same 34.5 kilovolt (kV) line.

On December 30, 2003, HELCO and Hawi Renewable Development, LLC (HRD LLC) entered into a PPA under which HRD LLC would sell energy from an expanded wind farm (approximately 10.6 MW) at HRD’s 5 MW wind farm site (which can accommodate the expanded wind farm). Since the KPP wind farm would not be built, it is anticipated that the output of the 10.6 MW wind farm would not be limited by another wind farm on the 34.5 kV line (although the output of the 10.6 MW wind farm may be limited on occasion due to other factors). PUC approval of the PPA is pending.

The PUC has approved and allowed rate recovery for the firm capacity and purchased energy costs for MECO’s and HELCO’s approved firm capacity and as-available energy PPAs.

Fuel oil usage and supply

The rate schedules of the Company’s electric utility subsidiaries include energy cost adjustment (ECA) clauses under which electric rates (and consequently the revenues of the electric utility subsidiaries generally) are 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. See discussion below under “Rates,” and “Regulation of electric utility rates” and “Electric utility revenues” in HECO’s MD&A.

HECO’s steam power plants burn LSFO. HECO’s combustion turbine peaking units burn No. 2 diesel fuel (diesel). MECO’s and HELCO’s steam power plants burn medium sulfur fuel oil (MSFO) and their combustion turbine and diesel engine generating units burn diesel. The LSFO supplied to HECO is primarily derived from Indonesian and other Far East crude oils processed in Hawaii refineries. The MSFO supplied to MECO and HELCO is derived from U.S. domestic crude oil processed in Hawaii refineries.

In December 1997, HECO executed contracts for the purchase of LSFO and the use of certain fuel distribution facilities with Chevron Products Company (Chevron) and BHP Petroleum Americas Refining Inc. (BHP). Subsequently, Tesoro Hawaii Corp. (Tesoro) acquired BHP and assumed all rights and obligations under the contract between HECO and BHP. The Chevron and BHP (now Tesoro) fuel supply and facilities operations contracts have a term of seven years commencing January 1, 1998. The PUC approved the contracts and permits the inclusion of

costs incurred under these contracts in HECO’s ECA clauses. HECO pays market-related prices for fuel supplies purchased under these agreements. HECO is currently negotiating with its fuel suppliers for new long-term LSFO supply agreements to replace those expiring at the end of 2004.

HECO, MECO and HELCO executed joint fuel supply contracts with Chevron and BHP (now Tesoro) for the purchase of diesel and MSFO supplies and for the use of certain petroleum distribution facilities for a period of seven years commencing January 1, 1998. The PUC approved these contracts and permits the electric utilities to include fuel costs incurred under these contracts in their respective ECA clauses. The electric utilities pay market-related prices for diesel and MSFO supplied under these agreements. HECO, HELCO and MECO are currently negotiating with its fuel suppliers for new long-term contracts for the supply of diesel and MSFO to replace those expiring at the end of 2004.

The diesel supplies acquired by the Lanai Division of MECO are purchased under a contract with a local petroleum wholesaler, Lanai Oil Co., Inc. On March 1, 2000, the PUC approved an amended contract with a term extending through December 31, 2001, and further extending through December 31, 2003 unless terminated as of the end of 2001. This agreement has been extended through December 31, 2004 and the utility anticipates that it will again continue for another year, through December 31, 2005, as provided by a provision in the existing contract.

See the fuel oil commitments information set forth in the “Fuel contracts” section in Note 11 to HECO’s Consolidated Financial Statements.

The following table sets forth the average cost of fuel oil used by HECO, MECO and HELCO to generate electricity in the years 2003, 2002 and 2001:


	HECO		MECO		HELCO		Consolidated
	$/Barrel	¢/MBtu	$/Barrel	¢/MBtu	$/Barrel	¢/MBtu	$/Barrel	¢/MBtu
2003	35.49	561.3	39.52	662.1	34.96	566.4	36.23	580.5
2002	27.95	442.3	32.78	548.5	30.58	496.7	29.10	466.4
2001	31.90	508.3	40.00	670.0	31.96	514.8	33.49	539.3

The average per-unit cost of fuel oil consumed to generate electricity for HECO, MECO and HELCO reflects a different volume mix of fuel types and grades. In 2003, over 99% of HECO’s generation fuel consumption consisted of LSFO. The balance of HECO’s fuel consumption was diesel. Diesel made up approximately 75% of MECO’s and 29% of HELCO’s fuel consumption. MSFO made up the remainder of the fuel consumption of MECO and HELCO. In general, MSFO is the least costly fuel, diesel is the most expensive fuel and the price of LSFO falls between the two on a per-barrel basis. During 2003, the prices of LSFO, MSFO and diesel remained at or above the high levels reached at the end of 2002 reflecting geopolitical uncertainty with the invasion of Iraq and tight U.S. crude oil and petroleum inventories. Thus the annual prices paid by the utilities for LSFO, MSFO and diesel averaged approximately 25%, 13% and 21%, respectively, above the average price for that grade of fuel in 2002. Even though the average price per barrel was lower in 2002 than 2001, the prices of LSFO, MSFO and diesel trended higher during 2002 from the level prevailing at the end of 2001. The utilities’ 2002 price for LSFO and diesel averaged approximately 7% and 16%, respectively, below the average price in 2001, while the price for MSFO averaged approximately 3% above the average price in 2001.

In December 2000, HELCO and MECO executed contracts of private carriage with Hawaiian Interisland Towing, Inc. (HITI) for the shipment of MSFO and diesel supplies from their fuel suppliers’ facilities on Oahu to storage locations on the islands of Hawaii and Maui, respectively, commencing January 1, 2002. These contracts were the result of a competitive bidding process and provide for the employment of a new double-hull bulk petroleum barge at freight rates approximately the same as prevailed under predecessor transportation contracts with HITI. The new barge entered utility service in March 2002. The contracts are for an initial term of 5 years with options for three additional 5-year extensions. On December 10, 2001, the PUC approved these contracts and issued a final order that permits HELCO and MECO to include the fuel transportation and related costs incurred under the provisions of these agreements in their respective ECA clauses.

HITI never takes title to the fuel oil or diesel fuel, but does have custody and control while the fuel is in transit from Oahu. If there were an oil spill in transit, HITI is contractually obligated to indemnify HELCO and/or MECO. HITI has liability insurance coverage for oil spill related damage of $1 billion. State law provides a cap of $700 million on liability

for releases of heavy fuel oil transported interisland by tank barge. HELCO and/or MECO may be responsible for any clean-up and/or fines that HITI or its insurance carrier does not cover.

The prices that HECO, MECO and HELCO pay for purchased energy from nonutility generators are generally linked to the price of oil. The AES Hawaii energy prices vary primarily with an inflation indicator. The energy prices for Kalaeloa, which purchases LSFO from Tesoro, vary primarily with world LSFO prices. The H-POWER, HC&S, PGV and HCPC energy prices are based on the electric utilities’ respective PUC-filed short-run avoided energy cost rates (which vary with their respective composite fuel costs), subject to minimum floor rates specified in their approved PPAs. The Hamakua Partners energy prices vary primarily with HELCO’s diesel costs.

The Company estimates that 78% of the net energy generated and purchased by HECO and its subsidiaries in 2004 will be generated from the burning of oil. Increases in fuel oil prices are passed on to customers through the electric utility subsidiaries’ ECA clauses. Failure by the Company’s oil suppliers to provide fuel pursuant to the supply contracts and/or substantial increases in fuel prices could adversely affect consolidated HECO’s and the Company’s financial condition, results of operations and/or liquidity. HECO, however, maintains an inventory of fuel oil in excess of one month’s supply. HELCO and MECO maintain approximately a one month’s supply of both MSFO and diesel. The PPAs with AES Hawaii and Hamakua Partners require that they maintain certain minimum fuel inventory levels.

Transmission systems

HECO has 138 kV transmission and 46 kV subtransmission lines. HELCO has 69 kV transmission and 34.5 kV subtransmission lines. MECO has 69 kV transmission and 23 kV subtransmission lines on Maui and 34.5 kV transmission lines on Molokai. Lanai has no transmission lines and uses 12 kV lines to distribute electricity. The electric utilities’ overhead and underground transmission and subtransmission lines, as well as their distribution lines, are uninsured because the amount of insurance available is limited and the premiums are extremely high.

Lines are added when needed to serve increased loads and/or for reliability reasons. In some design districts on Oahu, lines must be placed underground. By state law, the PUC generally must determine whether new 46 kV, 69 kV or 138 kV lines can be constructed overhead or must be placed underground. The process of acquiring permits and regulatory approvals for new lines can be contentious, time consuming (leading to project delays) and costly.

HECO system. HECO serves Oahu’s electricity requirements with firm capacity (net) generating units located in West Oahu (1,027 MW); Waiau, adjacent to Pearl Harbor (481 MW); and Honolulu (107 MW). HECO’s nonfirm power sources (approximately 28 MW) are located primarily in West Oahu. HECO transmits power to its service areas on Oahu through approximately 219 miles of overhead and underground 138 kV transmission lines (of which approximately 8 miles are underground) and approximately 570 miles of overhead and underground 46 kV subtransmission lines.

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 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 $55 million) for its revised East Oahu Transmission Project. See discussion in Note 11 to HECO’s Consolidated Financial Statements.

In March 2004, approximately 40,000 of HECO’s customers in the Honolulu//East Oahu area, including Waikiki, lost power for forty-five minutes to one and one-half hours. The areas affected are served by the Pukele substation. 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 effects of the outage could have been mitigated, and that the outage might have been prevented if the East Oahu Transmission Project had been completed.

HELCO system. HELCO serves the island of Hawaii’s electricity requirements with firm capacity (net) generating units located in West Hawaii (42 MW) and East Hawaii (213 MW). HELCO’s nonfirm power sources total 24 MW. HELCO transmits power to its service area on the island of Hawaii through approximately 468 miles of 69 kV overhead lines and approximately 173 miles of 34.5 kV overhead lines.

MECO system. MECO serves its electricity requirements with firm capacity (net) generating units located on the island of Maui (245 MW), Molokai (12 MW) and Lanai (10 MW). MECO has no nonfirm power sources. MECO transmits power to its service area through approximately 143 miles of 69 kV overhead lines, approximately 15 miles of 34.5 kV overhead lines, and approximately 85 miles of 23 kV overhead lines.

Rates

HECO, MECO and HELCO are subject to the regulatory jurisdiction of the PUC with respect to rates, issuance of securities, accounting and certain other matters. See “Regulation and other matters—Electric utility regulation.”

All rate schedules of HECO and its subsidiaries contain ECA clauses as described previously. Under current law and practices, specific and separate PUC approval is not required for each rate change pursuant to automatic rate adjustment clauses previously approved by the PUC. Rate increases, other than pursuant to such automatic adjustment clauses, require the prior approval of the PUC after public and contested case hearings. PURPA requires the PUC to periodically review the ECA clauses of electric and gas utilities in the state, and such clauses, as well as the rates charged by the utilities generally, are subject to change.

See “Regulation of electric utility rates,” “Recent rate requests” and “Electric utility revenues” in HECO’s MD&A.

Public Utilities Commission of the State of Hawaii

Carlito Caliboso has been the Chairman of the PUC since April 30, 2003. Mr. Caliboso is an attorney and was in private practice prior to his appointment. Continuing to serve on the PUC is Commissioner Wayne H. Kimura, who served as Chairman from July 2002 to April 2003 and Commissioner Janet E. Kawelo.

Most recent rate requests

See “Recent rate requests” in HECO’s MD&A.

Maui Electric Company, Limited. In January 1998, MECO filed a request to increase rates, based on a 1999 test year, primarily to recover costs relating to the addition of generating unit M17 in late 1998. In November 1998, MECO revised its requested increase to 11.9%, or $16.4 million, in annual revenues, based on a 12.75% return on average common equity (ROACE). In April 1999, MECO received an amended final D&O from the PUC which authorized an 8.2%, or $11.3 million, increase in annual revenues, based on a 1999 test year and a 10.94% ROACE. The timing of a future MECO rate increase cannot be determined at this time.

Competition

In December 1996, the PUC instituted a proceeding to identify and examine the issues surrounding electric competition and to determine the impact of competition on the electric utility infrastructure in Hawaii. See “Competition” in HECO’s MD&A.

Electric and magnetic fields

Research on potential adverse health effects from exposure to electric and magnetic fields (EMF) continues. To date, no definite relationship between EMF and health risks has been demonstrated. In 1996, the National Academy of Sciences examined more than 500 studies and stated that “the current body of evidence does not show that exposure to EMFs presents a human-health hazard.” An extensive study released in 1997 by the National Cancer Institute and the Children’s Cancer Group found no evidence of increased risk for childhood leukemia from EMF. In 1999, the National Institute of Environmental Health Sciences Director’s Report concluded that while EMF could not be found to be “entirely safe,” the evidence of a health risk was “weak” and did not warrant “aggressive” regulatory actions.

While EMF has not been established as a cause of any health condition, there were developments in 2002 and 2003. EMF was classified as a possible human carcinogen in reports from two public health organizations and in 2003, the U.K. National Radiological Protection Board (NRPB) published a consultation report that considered a precautionary approach and proposed limiting exposure to EMF. The implications of the reports and the NRPB proposals have not yet been determined.

HECO and its subsidiaries are monitoring the research and continue to participate in utility industry funded studies on EMF and, where technically feasible and economically reasonable, continue to reduce EMF in the design and installation of new transmission and distribution facilities. Management cannot predict the impact, if any, the EMF issue may have on HECO, HELCO and MECO in the future.

Legislation

See “Legislation” in HECO’s MD&A.

Commitments and contingencies

See “Certain factors that may affect future results and financial condition–Other regulatory and permitting contingencies” in HECO’s MD&A and Note 11 to HECO’s Consolidated Financial Statements for a discussion of important commitments and contingencies, including (but not limited to) HELCO’s Keahole power situation, HECO’s East Oahu Transmission Project, the lawsuit against The AES Corporation and the Company, and the Honolulu Harbor environmental investigation.

Bank—American Savings Bank, F.S.B.

General

ASB was granted a federal savings bank charter in January 1987. Prior to that time, ASB had operated since 1925 as the Hawaii division of American Savings & Loan Association of Salt Lake City, Utah. As of December 31, 2003, ASB was the third largest financial institution in the State of Hawaii based on total assets of $6.5 billion and deposits of $4.0 billion. In 2003, ASB’s revenues and net income from continuing operations amounted to approximately 21% and 48%, respectively, of HEI’s consolidated amounts, compared to approximately 24% and 48% in 2002 and approximately 26% and 45% in 2001, respectively.

At the time of HEI’s acquisition of ASB in 1988, HEI agreed with the Office of Thrift Supervision’s (OTS) predecessor regulatory agency that ASB’s regulatory capital would be maintained at a level of at least 6% of ASB’s total liabilities, or at such greater amount as may be required from time to time by regulation. Under the agreement, HEI’s obligation to contribute additional capital was limited to a maximum aggregate amount of approximately $65.1 million. At December 31, 2003, HEI’s maximum obligation to contribute additional capital has been reduced to approximately $28.3 million because of additional capital contributions of $36.8 million by HEI to ASB since the acquisition, exclusive of capital contributions made in connection with ASB’s acquisition of most of the Hawaii operations of Bank of America, FSB. ASB is subject to OTS regulations on dividends and other distributions applicable to financial institutions regulated by the OTS and ASB must receive a letter of non-objection before it can declare and pay a dividend to HEI.

The accounting treatment for goodwill and other intangible assets has changed for 2002 and subsequent years such that goodwill is no longer amortized, but other intangible assets continue to be amortized, and goodwill and other intangible assets are reviewed for impairment at least annually. See “Goodwill and other intangibles” in Note 1 to HEI’s Consolidated Financial Statements.

ASB’s earnings depend primarily on its net interest income—the difference between the interest income earned on interest-earning assets (loans receivable and investment and mortgage-related securities) and the interest expense incurred on interest-bearing liabilities (deposit liabilities and borrowings, including advances from the Federal Home Loan Bank (FHLB) of Seattle and securities sold under agreements to repurchase).

For additional information about ASB, see the sections under “Bank” in HEI’s MD&A, HEI’s “Quantitative and Qualitative Disclosures about Market Risk” and Note 4 to HEI’s Consolidated Financial Statements.

The following table sets forth selected data for ASB for the years indicated:


	Years ended December 31,
	2003		2002		2001
Common equity to assets ratio
Average common equity divided by average total assets ¹	7.20	%	7.20	%	6.65	%
Return on assets
Net income for common stock divided by average total assets ^1, 2	0.88		0.92		0.81
Return on common equity
Net income for common stock divided by average common equity ^1, 2	12.2		12.7		12.3
Tangible efficiency ratio
Total general and administrative expenses divided by net interest income and other income	61		58		56

¹	Average balances calculated using the average daily balances (except for common equity, which is calculated using the average month-end balance).

²	In 2001, net income includes amortization of goodwill and other intangibles. In 2003 and 2002, goodwill is no longer amortized, but other intangibles are still amortized, and goodwill and other intangibles are tested for impairment at least annually.

ASB’s tangible efficiency ratio – the cost of earning $1 of revenue – rose from 56% for 2001 to 61% for 2003 due to expenditures toward the strategic transformation which began in 2002. In 2002, general and administrative expenses grew at a faster pace than net interest income and other income as ASB began implementation of strategic changes to become a full-service community bank. It is expected that this increased expense level will continue in 2004.

Consolidated average balance sheet

The following table sets forth average balances of ASB’s major balance sheet categories for the years indicated. Average balances have been calculated using the daily average balances.


	Years ended December 31,
(in thousands)	2003		2002		2001
Assets
Investment securities	$	200,891	$	246,321	$	308,712
Mortgage-related securities		2,707,395		2,654,302		2,345,630
Loans receivable, net		3,071,877		2,844,341		2,963,521
Other		418,296		392,338		391,040

	$	6,398,459	$	6,137,302	$	6,008,903

Liabilities and stockholder’s equity
Savings deposits	$	2,663,325	$	2,394,435	$	2,059,486
Term certificates		1,224,820		1,323,118		1,578,650
Other borrowings		1,851,258		1,770,831		1,778,766
Other		123,167		132,223		117,366
Stockholder’s equity		535,889		516,695		474,635

	$	6,398,459	$	6,137,302	$	6,008,903

In 2003, the low interest rate environment and continued strength in the Hawaii real estate market drove record loan production and an increase in average loans receivables. The average residential mortgage portfolio as of year-end 2003 grew by $193.6 million or 8.5% over the 2002 year-end average residential mortgage portfolio. ASB’s average business portfolio increased by $51.9 million or 23.5% during 2003 as ASB’s transformation to a full-service community bank continued. Average savings deposits increased during the year as ASB continued to attract core deposits. Average term certificate balances decreased in 2003 as ASB did not aggressively pursue term certificates. Average other borrowings increased during 2003 to replace the outflow of term certificates. In 2002, the increase in the average balance for mortgage-related securities was due to the exchange of loans for $0.4 billion of mortgage-related securities in 2001 and the investment of excess liquidity into mortgage-related

securities. In 2002, the decrease in the average balance of loans receivable was due to the exchange of loans for mortgage-related securities in 2001 and the high loan prepayments in 2002 as result of the low interest rate environment. In 2002, the increase in savings deposits and the decrease in term certificates were due to ASB’s efforts in attracting low-costing core deposits and depositors not willing to have their funds invested for long periods of time at current interest rates as the low interest rate environment has brought term certificate interest rates down near core deposit interest rates.

Asset/liability management

See HEI’s “Quantitative and Qualitative Disclosures about Market Risk” in HEI’s Annual Report.

Interest income and interest expense

See “Results of operations—Bank” in HEI’s MD&A for a table of 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 years ended December 31, 2003, 2002 and 2001.

The following table shows the effect on net interest income of (1) changes in interest rates (change in weighted-average interest rate multiplied by prior year average portfolio balance) and (2) changes in volume (change in average portfolio balance multiplied by prior period rate). Any remaining change is allocated to the above two categories on a pro rata basis.


	Increase (decrease) due to
(in thousands)	Rate			Volume			Total
Year ended December 31, 2003 vs. 2002
Income from interest-earning assets
Loan portfolio	$	(19,637	)	$	15,503		$	(4,134	)
Mortgage-related securities		(30,425	)		2,669			(27,756	)
Investments		(73	)		(1,439	)		(1,512	)

		(50,135	)		16,733			(33,402	)

Expense from interest-bearing liabilities
Deposits		(18,338	)		(1,485	)		(19,823	)
FHLB advances and other borrowings		(13,209	)		3,474			(9,735	)

		(31,547	)		1,989			(29,558	)

Net interest income	$	(18,588	)	$	14,744		$	(3,844	)

Year ended December 31, 2002 vs. 2001
Income from interest-earning assets
Loan portfolio	$	(19,676	)	$	(9,100	)	$	(28,776	)
Mortgage-related securities		(35,306	)		18,377			(16,929	)
Investments		(4,969	)		(2,747	)		(7,716	)

		(59,951	)		6,530			(53,421	)

Expense from interest-bearing liabilities
Deposits		(35,062	)		(7,838	)		(42,900	)
FHLB advances and other borrowings		(17,372	)		(431	)		(17,803	)

		(52,434	)		(8,269	)		(60,703	)

Net interest income	$	(7,517	)	$	14,799		$	7,282

Other income

In addition to net interest income, ASB has various sources of other income, including fee income from servicing loans, fee income from financial products and services, fees on deposit accounts and other income. Other income totaled approximately $58.5 million in 2003, $53.0 million in 2002 and $45.0 million in 2001. The increase in other income for 2003 was due to net gains on sales of securities totaling $4.1 million compared to a net loss of $0.6 million in 2002, higher fee income from its debit and automated teller machines (ATM) cards resulting from ASB’s expansion of its debit card base and additional ATM services and higher fee income from its deposit liabilities as a result of restructuring of deposit products. Offsetting these increases were lower gains on sales of loans in 2003 compared to 2002 and a lower accrual for the costs of administering delinquent loans in 2002. The increase in

other income for 2002 was due to increases in fee income from its debit and ATM cards and higher fee income from its deposit liabilities. Increased fee income from Bishop Insurance Agency of Hawaii, Inc. (BIA) which was acquired in March 2001 also contributed to the increase in other income. Offsetting these increases were lower fee income on loans serviced for others as ASB recorded writedowns of its mortgage servicing rights due to faster prepayments on its servicing portfolio and a net loss of $0.6 million on the sale of securities compared to a net gain of $8.0 million in 2001.

Lending activities

General. Loans and mortgage-related securities of $5.8 billion represented 88.8% of total assets at December 31, 2003, compared to $5.7 billion, or 90.6%, and $5.2 billion, or 86.7%, at December 31, 2002 and 2001, respectively. ASB’s loan portfolio consists primarily of conventional residential mortgage loans, which are neither insured by the Federal Housing Administration nor guaranteed by the Veterans Administration.

The following tables set forth the composition of ASB’s loan and mortgage-related securities portfolio:


	December 31,
	2003					2002					2001
(dollars in thousands)	Balance			% of total		Balance			% of total		Balance			% of total
Real estate loans ¹
Conventional (1-4 unit residential)	$	2,505,059		43.28	%	$	2,389,852		41.70	%	$	2,294,372		44.02	%
Commercial real estate		200,320		3.46			197,371		3.45			196,515		3.77

		2,705,379		46.74			2,587,223		45.15			2,490,887		47.79
Less
Deferred fees and discounts		(20,268	)	(0.35	)		(18,937	)	(0.33	)		(17,946	)	(0.34	)
Undisbursed loan funds		(27,021	)	(0.47	)		(21,412	)	(0.37	)		(22,910	)	(0.45	)
Allowance for loan losses		(14,734	)	(0.26	)		(23,708	)	(0.42	)		(26,085	)	(0.50	)

Total real estate loans, net		2,643,356		45.66			2,523,166		44.03			2,423,946		46.50

Other loans
Consumer and other loans		222,743		3.85			245,853		4.29			252,487		4.84
Commercial loans		286,068		4.94			247,114		4.31			197,333		3.79

		508,811		8.79			492,967		8.60			449,820		8.63
Less
Deferred fees and discounts		(606	)	(0.01	)		(416	)	—			—		—
Undisbursed loan funds		(31	)	—			(1	)	—			(5	)	—
Allowance for loan losses		(29,551	)	(0.51	)		(21,727	)	(0.38	)		(16,139	)	(0.31	)

Total other loans, net		478,623		8.27			470,823		8.22			433,676		8.32

Mortgage-related securities, net of discounts		2,666,619		46.07			2,736,679		47.75			2,354,849		45.18

Total loans and mortgage-related securities, net	$	5,788,598		100.00	%	$	5,730,668		100.00	%	$	5,212,471		100.00	%

¹	Includes renegotiated loans. In 2001, ASB exchanged loans for $0.4 billion of mortgage-related securities.


	December 31,
	2000					1999
(dollars in thousands)	Balance			% of total		Balance			% of total
Real estate loans ¹
Conventional (1-4 unit residential)	$	2,758,667		52.23	%	$	2,769,101		53.40	%
Commercial real estate		156,177		2.95			170,663		3.29

		2,914,844		55.18			2,939,764		56.69
Less
Deferred fees and discounts		(21,588	)	(0.41	)		(24,083	)	(0.46	)
Undisbursed loan funds		(17,559	)	(0.33	)		(19,368	)	(0.37	)
Allowance for loan losses		(24,800	)	(0.47	)		(22,319	)	(0.43	)

Total real estate loans, net		2,850,897		53.97			2,873,994		55.43

Other loans
Consumer and other loans		238,351		4.51			244,933		4.72
Commercial loans		134,784		2.55			106,098		2.05

		373,135		7.06			351,031		6.77
Less
Deferred fees and discounts		—		—			—		—
Undisbursed loan funds		(58	)	—			(118	)	—
Allowance for loan losses		(12,649	)	(0.24	)		(13,029	)	(0.25	)

Total other loans, net		360,428		6.82			337,884		6.52

Mortgage-related securities, net of discounts		2,070,827		39.21			1,973,146		38.05

Total loans and mortgage-related securities, net	$	5,282,152		100.00	%	$	5,185,024		100.00	%

¹	Includes renegotiated loans.

The following table summarizes ASB’s loan portfolio, excluding loans held for sale, at December 31, 2003 and 2002, based upon contractually scheduled principal payments and expected prepayments allocated to the indicated maturity categories:


December 31, 2003	Due
(in millions)	Less than 1 year		1-5 years		After 5 years		Total
Residential loans
Fixed	$	401	$	866	$	783	$	2,050
Adjustable		123		237		86		446

		524		1,103		869		2,496

Commercial real estate loans
Fixed		5		19		17		41
Adjustable		28		47		84		159

		33		66		101		200

Consumer loans
Fixed		15		32		17		64
Adjustable		52		84		23		159

		67		116		40		223

Commercial loans
Fixed		91		57		29		177
Adjustable		59		43		7		109

		150		100		36		286

	$	774	$	1,385	$	1,046	$	3,205


December 31, 2002	Due
(in millions)	Less than 1 year		1-5 years		After 5 years		Total
Residential loans
Fixed	$	497	$	484	$	848	$	1,829
Adjustable		208		226		112		546

		705		710		960		2,375

Commercial real estate loans
Fixed		6		26		26		58
Adjustable		19		43		77		139

		25		69		103		197

Consumer loans
Fixed		17		42		22		81
Adjustable		59		89		17		165

		76		131		39		246

Commercial loans
Fixed		90		36		13		139
Adjustable		54		42		12		108

		144		78		25		247

	$	950	$	988	$	1,127	$	3,065

Origination, purchase and sale of loans. Generally, residential and commercial real estate loans originated by ASB are secured by real estate located in Hawaii. As of December 31, 2003, approximately $14.9 million of loans purchased from other lenders were secured by properties located in the continental United States. For additional information, including information concerning the geographic distribution of ASB’s mortgage-related securities portfolio and the geographic concentration of credit risk, see Note 12 to HEI’s Consolidated Financial Statements.

The amount of loans originated during 2003, 2002, 2001, 2000 and 1999 were $1.6 billion, $1.2 billion, $1.0 billion, $0.5 billion and $0.6 billion, respectively. The demand for loans is primarily dependent on the Hawaii real estate market, interest rates and loan refinancing activity. The increase in loan originations in 2003, 2002 and 2001 was due to the strength in the Hawaii real estate market and low interest rates which have resulted in increased affordability of housing for consumers and higher loan refinancings.

Residential mortgage lending. ASB is permitted to lend up to 100% of the appraised value of the real property securing a loan. Its general policy is to require private mortgage insurance when the loan-to-value ratio of the property exceeds 80% of the lower of the appraised value or purchase price at origination. For nonowner-occupied residential properties, the loan-to-value ratio may not exceed 90% of the lower of the appraised value or purchase price at origination.

Construction and development lending. ASB provides both fixed- and adjustable-rate loans for the construction of one-to-four unit residential and commercial properties. Construction and development financing generally involves a higher degree of credit risk than long-term financing on improved, occupied real estate. Accordingly, all construction and development loans are priced higher than loans secured by completed structures. ASB’s underwriting, monitoring and disbursement practices with respect to construction and development financing are designed to ensure sufficient funds are available to complete construction projects. As of December 31, 2003, 2002 and 2001, ASB had construction and development loans of $72.8 million, $46.2 million and $52.0 million, which represented 2.3%, 1.5% and 1.8%, respectively, of ASB’s gross loan portfolio. In 2003, the increase in construction and development was due to an increase in commercial real estate lending. See “Loan portfolio risk elements.”

Multifamily residential and commercial real estate lending. ASB provides permanent financing and construction and development financing secured by multifamily residential properties (including apartment buildings) and secured by commercial and industrial properties (including office buildings, shopping centers and warehouses) for its own portfolio as well as for participation with other lenders. In 2003, 2002 and 2001, ASB originated $81.3 million, $66.0 million and $62.7 million loans secured by multifamily or commercial and industrial properties. Beginning in 2001, ASB enhanced its commercial real estate lending capabilities and plans to continue to increase commercial real estate lending in the future. The objective of commercial real estate lending is to diversify ASB’s loan portfolio as commercial and real estate loans tend to have higher yields and shorter durations than residential mortgage loans.

Consumer lending. ASB offers a variety of secured and unsecured consumer loans. Loans secured by deposits are limited to 90% of the available account balance. ASB also offers secured and unsecured VISA cards, automobile loans, general purpose consumer loans, home equity lines of credit, checking account overdraft protection and unsecured lines of credit. In 2003, 2002 and 2001, gross consumer loan originations of $138.1 million, $131.8 million and $191.5 million, accounted for approximately 8.6%, 10.8% and 18.3%, respectively, of ASB’s total loan originations. In 2001, ASB increased its VISA credit card base by approximately 50%, primarily as a result of ASB’s implementation of an aggressive series of mail solicitation campaigns to extend consumer credit to existing customers.

Business lending. ASB is authorized to make both secured and unsecured business loans to business entities. This lending activity is part of ASB’s strategic transformation to a full-service community bank and is designed to diversify ASB’s asset structure, shorten maturities, improve rate sensitivity of the loan portfolio and attract business checking deposits. As of December 31, 2003, 2002 and 2001, business loans represented 9.2%, 8.3% and 6.9%, respectively, of ASB’s total net loan portfolio.

Loan origination fee and servicing income. In addition to interest earned on loans, ASB receives income from servicing loans, for late payments and from other related services. Servicing fees are received on loans originated and subsequently sold by ASB through a securitization process and also on loans for which ASB acts as collection agent on behalf of third-party purchasers. See “Results of operations—Bank” in HEI’s MD&A for a discussion of ASB’s 2002 writedown of mortgage servicing rights.

ASB generally charges the borrower at loan settlement a loan origination fee of 1% of the amount borrowed. See “Loans receivable” in Note 1 to HEI’s Consolidated Financial Statements.

Loan portfolio risk elements. When a borrower fails to make a required payment on a loan and does not cure the delinquency promptly, the loan is classified as delinquent. If delinquencies are not cured promptly, ASB normally commences a collection action, including foreclosure proceedings in the case of secured loans. In a foreclosure action, the property securing the delinquent debt is sold at a public auction in which ASB may participate as a bidder to protect its interest. If ASB is the successful bidder, the property is classified in a real estate owned account until it is sold. ASB’s real estate acquired in settlement of loans represented 0.12%, 0.19% and 0.24% of total assets at December 31, 2003, 2002 and 2001, respectively.

In addition to delinquent loans, other significant lending risk elements include: (1) loans which accrue interest and are 90 days or more past due as to principal or interest, (2) loans accounted for on a nonaccrual basis (nonaccrual loans), and (3) loans on which various concessions are made with respect to interest rate, maturity, or other terms due to the inability of the borrower to service the obligation under the original terms of the agreement (renegotiated loans). The level of delinquent and nonaccrual loans represented 0.7%, 1.1%, 2.3%, 2.2%, and 2.4% of ASB’s total net loans outstanding at December 31, 2003, 2002, 2001, 2000 and 1999, respectively. ASB had no loans that were 90 days or more past due on which interest was being accrued as of the dates presented in the table below. The following table sets forth certain information with respect to nonaccrual and renegotiated loans as of the dates indicated:


	December 31,
(in thousands)	2003			2002			2001			2000			1999
Nonaccrual loans—
Real estate
1-4 unit residential	$	2,784		$	9,783		$	22,495		$	26,738		$	43,750
Income property		—			983			10,129			15,132			18,747

Total real estate		2,784			10,766			32,624			41,870			62,497
Consumer		341			1,382			1,965			2,844			3,777
Commercial		2,236			3,633			3,018			2,872			2,192

Total nonaccrual loans	$	5,361		$	15,781		$	37,607		$	47,586		$	68,466

Nonaccrual loans to total net loans		0.2	%		0.5	%		1.3	%		1.4	%		2.1	%

Renegotiated loans not included above—
Real estate
1-4 unit residential	$	2,148		$	—		$	—		$	48		$	876
Income property		3,877			7,582			3,874			—			5,154
Commercial		1,919			2,175			2,681			—			—

Total renegotiated loans	$	7,944		$	9,757		$	6,555		$	48		$	6,030

Nonaccrual and renegotiated loans to total net loans		0.4	%		0.9	%		1.5	%		1.5	%		2.3	%

ASB’s policy generally is to place mortgage loans on a nonaccrual status (i.e., interest accrual is suspended) when the loan becomes 90 days or more past due or on an earlier basis when there is a reasonable doubt as to its collectibility.

In 2000, the $20.9 million decrease in nonaccrual loans was primarily due to increased charge-offs and lower delinquencies. In 2001, the decrease in nonaccrual loans of $10.0 million was primarily due to lower delinquencies in residential loans and an income property loan taken into real estate owned. In 2002, the decrease in nonaccrual loans of $21.8 million was due to $12.7 million lower delinquencies in residential loans, a $5.0 million payoff of an income property loan and a $4.1 million reclassification of an income property loan to accrual status. In 2003, the

decrease in nonaccrual loans of $10.4 million was primarily due to $7.0 million lower delinquencies in residential loans as a result of improved credit quality of ASB’s loan portfolio due to the strong real estate market in Hawaii.

Allowance for loan losses. See Note 1 to HEI’s Consolidated Financial Statements.

The following table presents the changes in the allowance for loan losses for the years indicated:


	Years ended December 31,
(dollars in thousands)	2003			2002			2001			2000			1999
Allowance for loan losses, beginning of year	$	45,435		$	42,224		$	37,449		$	35,348		$	39,779
Provision for loan losses		3,075			9,750			12,500			13,050			16,500
Charge-offs
Residential real estate loans		892			2,345			4,651			8,867			4,962
Commercial real estate loans		174			441			315			—			10,776
Consumer loans		3,027			3,479			3,644			3,801			4,712
Commercial loans		2,601			1,479			1,013			670			1,209

Total charge-offs		6,694			7,744			9,623			13,338			21,659

Recoveries
Residential real estate loans		1,244			858			1,210			1,926			448
Commercial real estate loans		426			52			342			214			75
Consumer loans		586			257			313			244			188
Commercial loans		213			38			33			5			17

Total recoveries		2,469			1,205			1,898			2,389			728

Allowance for loan losses, end of year	$	44,285		$	45,435		$	42,224		$	37,449		$	35,348

Ratio of allowance for loan losses, December 31, to average loans outstanding		1.44	%		1.60	%		1.42	%		1.16	%		1.11	%

Ratio of provision for loan losses during the year to average loans outstanding		0.10	%		0.34	%		0.42	%		0.41	%		0.52	%

Ratio of net charge-offs during the year to average loans outstanding		0.14	%		0.23	%		0.26	%		0.34	%		0.66	%

The following table sets forth the allocation of ASB’s allowance for loan losses and the percentage of loans in each category to total loans at the dates indicated:


December 31	2003				2002				2001				2000				1999
(dollars in thousands)	Balance		% of total		Balance		% of total		Balance		% of total		Balance		% of total		Balance		% of total
Residential real estate	$	4,031	78.0	%	$	6,246	77.6	%	$	9,933	78.0	%	$	13,224	83.9	%	$	14,394	84.2	%
Commercial real estate		6,008	6.2			6,343	6.4			9,031	6.7			8,928	4.7			7,963	5.2
Consumer		6,540	6.9			8,489	8.0			8,538	8.6			7,609	7.3			9,850	7.4
Commercial		14,758	8.9			12,118	8.0			6,388	6.7			4,126	4.1			3,060	3.2
Unallocated		12,948	NA			12,239	NA			8,334	NA			3,562	NA			81	NA

	$	44,285	100.0	%	$	45,435	100.0	%	$	42,224	100.0	%	$	37,449	100.0	%	$	35,348	100.0	%

NA	Not applicable.

In 2003, ASB’s allowance for loan losses decreased by $1.2 million compared to an increase of $3.2 million in 2002. The decrease in 2003 was due to lower net charge-offs as a result of lower delinquencies. The increasing value of Hawaii real estate and continued low interest rates gave debtors the opportunity to sell their properties or refinance before defaulting. ASB also continued to improve its collection efforts. Residential, consumer and

commercial real estate loan delinquencies continued to decrease during 2003 and lower loan loss reserves were required for those lines of business. The growth in the commercial loan portfolio as a result of ASB’s strategic focus of diversifying its loan portfolio from single-family home mortgages to commercial loans has required additional loan loss reserves. The unallocated component of the allowance for loan losses, which takes into consideration economic trends and estimation errors that are not necessarily captured in determining the allowance for loan losses for each category, increased slightly. In 2002, ASB’s allowance for loan losses increased by $3.2 million compared to an increase of $4.8 million in 2001. The 2002 increase was due to a higher loans receivable balance and a higher unallocated component of the allowance for loan losses. The allowance was increased to account for ASB’s strategic focus of diversifying its loan portfolio from single-family home mortgages to commercial loans that have higher credit risk. Charge-offs were lower in 2002 compared to 2001 as a result of lower delinquencies. The strong Hawaii real estate market and low interest rates gave debtors the opportunity to sell their properties or refinance before defaulting. In addition, ASB improved its collection efforts. Residential and commercial real estate loan delinquencies decreased during 2002 and lower loan loss reserves were required for those lines of business. The allowance for loan losses on consumer loans remained essentially the same during 2002. In 2001, ASB’s allowance for loan losses increased by $4.8 million. Charge-offs were lower in 2001 compared to 2000 as a result of lower delinquencies. The 2001 increase in the allowance for loan losses was due to the increase in commercial real estate and commercial loans in the loan portfolio that have higher credit risk and a higher unallocated component of the allowance, which takes into consideration economic trends and estimation errors that are not necessarily captured in determining the allowance for loan losses for each loan category. In 2000, ASB’s allowance for loan losses increased by $2.1 million. Charge-offs were lower in 2000 compared to 1999 as a result of lower delinquencies.

Investment activities

In recent years, ASB’s investment portfolio consisted primarily of stock of the FHLB of Seattle, federal agency obligations and mortgage-related securities. ASB owns private-issue mortgage-related securities as well as investment and mortgage-related securities issued by the Federal Home Loan Mortgage Corporation (FHLMC), Government National Mortgage Association (GNMA) and Federal National Mortgage Association (FNMA). At December 31, 2003, the various securities rating agencies rated all of the private-issue mortgage-related securities as investment grade. ASB did not maintain a portfolio of securities held for trading during 2003, 2002 or 2001.

As of December 31, 2003, 2002 and 2001, ASB’s held-to-maturity investment portfolio consisted of $94.6 million, $89.5 million and $84.2 million, respectively, of investment in FHLB stock. The weighted-average rate on investments during 2003, 2002 and 2001 was 5.45%, 6.19% and 7.28%, respectively. The amount that ASB is required to invest in FHLB stock is determined by regulatory requirements. See “Regulation and other matters—Bank regulation—Federal Home Loan Bank System.”

The following table summarizes ASB’s investment portfolio, at December 31, 2003, based upon contractually scheduled principal payments and expected prepayments allocated to the indicated maturity categories:


(in millions)	Less than 1 year			1-5 years			6-10 years			After 10 years			Total
Federal agency obligations	$	—		$	50		$	—		$	—		$	50
FHLMC, GNMA, FNMA		598			1,292			371			104			2,365
Private issue		180			109			4			8			301

	$	778		$	1,451		$	375		$	112		$	2,716

Weighted average yield		4.53	%		4.40	%		3.58	%		4.31	%

Note: ASB does not currently invest in tax exempt obligations.

On January 1, 2001, ASB reclassified a significant amount of securities from held-to-maturity to available-for-sale (see “Derivative instruments and hedging activities” in Note 1 to HEI’s Consolidated Financial Statements). Securities classified as available-for-sale are reported at fair value, with unrealized gains and losses excluded from earnings and reported in a separate component of stockholders’ equity (see “Material estimates and critical accounting policies—Consolidated—Investment securities” in HEI’s MD&A). At December 31, 2003, ASB had

mortgage-related securities issued by FHLMC, GNMA and FNMA valued at $2.4 billion and private-issue mortgage-related securities valued at $0.3 billion in its available-for-sale investment portfolio.

Disposition of certain debt securities and related litigation. See Note 4 to HEI’s Consolidated Financial Statements.

Deposits and other sources of funds

General. Deposits traditionally have been the principal source of ASB’s funds for use in lending, meeting liquidity requirements and making investments. ASB also derives funds from the receipt of interest and principal on outstanding loans receivable and mortgage-related securities, borrowings from the FHLB of Seattle, securities sold under agreements to repurchase and other sources. ASB borrows on a short-term basis to compensate for seasonal or other reductions in deposit flows. ASB also may borrow on a longer-term basis to support expanded lending or investment activities. Advances from the FHLB and securities sold under agreements to repurchase continue to be a significant source of funds that have a higher cost of funds than core deposits.

Deposits. ASB’s deposits are obtained primarily from residents of Hawaii. In 2003 and 2002, ASB had average deposits of $3.9 billion and $3.7 billion, respectively. Net savings inflow in 2003, 2002 and 2001 was $225.5 million, $121.2 million and $94.9 million, respectively. In the three years ended December 31, 2003, ASB had no deposits placed by or through a broker.

The following table illustrates the distribution of ASB’s average deposits and average daily rates by type of deposit for the years indicated. Average balances have been calculated using the average daily balances.


	Years ended December 31,
	2003						2002
(dollars in thousands)	Average balance		% of total deposits		Weighted average rate%		Average balance		% of total deposits		Weighted average rate%
Savings accounts	$	1,352,507	34.8	%	0.56	%	$	1,188,042	31.9	%	1.22	%
Negotiable order of withdrawal accounts		913,228	23.5		0.05			802,651	21.6		0.13
Money market accounts		397,590	10.2		0.61			403,742	10.9		1.51
Certificate accounts		1,224,820	31.5		3.54			1,323,118	35.6		3.92

Total deposits	$	3,888,145	100.0	%	1.38	%	$	3,717,553	100.0	%	1.98	%


	Year ended December 31, 2001
(dollars in thousands)	Average balance		% of total deposits		Weighted average rate%
Savings accounts	$	1,049,441	28.9	%	1.91	%
Negotiable order of withdrawal accounts		699,997	19.2		0.59
Money market accounts		310,048	8.5		2.40
Certificate accounts		1,578,650	43.4		5.38

Total deposits	$	3,638,136	100.0	%	3.20	%

At December 31, 2003, ASB had $249.6 million in certificate accounts of $100,000 or more, maturing as follows:


(in thousands)	Amount
Three months or less	$	79,954
Greater than three months through six months		33,121
Greater than six months through twelve months		36,265
Greater than twelve months		100,261

	$	249,601

Deposit-insurance premiums and regulatory developments. The Savings Association Insurance Fund (SAIF) insures the deposit accounts of ASB and other thrifts. The Bank Insurance Fund (BIF) insures the deposit accounts of commercial banks. The Federal Deposit Insurance Corporation (FDIC) administers the SAIF and BIF. In December 1997, ASB acquired BIF–assessable deposits as well as SAIF–assessable deposits from Bank of America, FSB. Congress is currently considering legislation which would merge the SAIF and the BIF. This legislation is supported by the FDIC.

In December 1996, the FDIC adopted a risk-based base rate schedule for SAIF deposits, effective January 1, 1997, that was identical to the existing risk-based base rate schedule for BIF deposits: zero to 27 cents per $100 of deposits. Added to this base rate schedule through 1999 was the assessment to fund the Financing Corporation’s (FICO’s) interest obligations, which assessment was initially set at 6.48 cents per $100 of deposits for SAIF deposits and 1.3 cents per $100 of deposits for BIF deposits (subject to quarterly adjustment). By law, the FICO’s assessment rate on deposits insured by the BIF had to be one-fifth the rate on deposits insured by the SAIF until January 1, 2000. Effective January 1, 2000, the assessment rate for funding FICO interest payments became identical for SAIF and BIF deposits. The assessment rate for funding FICO interest payments is determined quarterly and, as a “well capitalized” thrift, ASB’s base deposit insurance premium effective for the December 31, 2003 quarterly payment is zero and its assessment for funding FICO interest payments is 1.54 cents per $100 of SAIF and BIF deposits, on an annual basis, based on deposits as of September 30, 2003.

Borrowings. ASB obtains advances from the FHLB of Seattle provided certain standards related to creditworthiness have been met. Advances are secured by a blanket pledge of certain notes held by ASB and the mortgages securing them. To the extent that advances exceed the amount of mortgage loan collateral pledged to the FHLB of Seattle, the excess must be covered by qualified marketable securities held under the control of and at the FHLB of Seattle or at an approved third party custodian. FHLB advances generally are available to meet seasonal and other withdrawals of deposit accounts, to expand lending and to assist in the effort to improve asset and liability management. FHLB advances are made pursuant to several different credit programs offered from time to time by the FHLB of Seattle.

At December 31, 2003, 2002 and 2001, advances from the FHLB amounted to $1.0 billion, $1.2 billion and $1.0 billion, respectively. The weighted-average rates on the advances from the FHLB outstanding at December 31, 2003, 2002 and 2001 were 4.28%, 5.10% and 5.41%, respectively. The maximum amount outstanding at any month-end during 2003, 2002 and 2001 was $1.1 billion, $1.2 billion and $1.2 billion, respectively. Advances from the FHLB averaged $1.0 billion, $1.1 billion and $1.2 billion during 2003, 2002 and 2001, respectively, and the approximate weighted-average rate on the advances was 4.62%, 5.29% and 5.98%, respectively.

Securities sold under agreements to repurchase are accounted for as financing transactions and the obligations to repurchase these securities are recorded as liabilities in the consolidated statements of financial condition. The securities underlying the agreements to repurchase continue to be reflected in the asset accounts (see Note 4 to HEI’s Consolidated Financial Statements). At December 31, 2003, 2002 and 2001, the entire outstanding amounts under these agreements of $831 million (including accrued interest of $1.8 million), $667 million (including accrued interest of $6.4 million) and $683 million (including accrued interest of $4.9 million), respectively, were to purchase identical securities. The weighted-average rates on securities sold under agreements to repurchase outstanding at December 31, 2003, 2002 and 2001 were 2.50%, 3.17% and 2.81%, respectively. The maximum amount outstanding at any month-end during 2003, 2002 and 2001 was $958 million, $751 million and $722 million, respectively. Securities sold under agreements to repurchase averaged $807 million, $663 million and $629 million during 2003, 2002 and 2001, respectively, and the approximate weighted-average interest rate under those agreements was 2.63%, 3.11% and 4.50%, respectively.

The following table sets forth information concerning ASB’s advances from the FHLB and securities sold under agreements to repurchase at the dates indicated:


	December 31,
(dollars in thousands)	2003			2002			2001
Advances from the FHLB	$	1,017,053		$	1,176,252		$	1,032,752
Securities sold under agreements to repurchase		831,335			667,247			683,180

Total borrowings	$	1,848,388		$	1,843,499		$	1,715,932

Weighted-average rate		3.48	%		4.40	%		4.37	%

Competition

The banking industry in Hawaii is highly competitive. ASB is the third largest financial institution in Hawaii and is in direct competition for deposits and loans, not only with the two larger institutions, but also with smaller institutions that are heavily promoting their services in certain niche areas, such as providing financial services to small and medium-sized businesses. ASB’s main competitors are banks, savings associations, credit unions, mortgage bankers, mortgage brokers, finance companies and brokerage firms. These competitors offer a variety of financial products to retail and business customers.

The primary factors in competing for deposits are interest rates, the quality and range of services offered, marketing, convenience of locations, hours of operation and perceptions of the institution’s financial soundness and safety. Competition for deposits comes primarily from other savings institutions, commercial banks, credit unions, money market and mutual funds and other investment alternatives. In Hawaii, there were 2 thrifts, 6 FDIC-insured banks and approximately 100 credit unions at December 31, 2003. Additional competition for deposits comes from various types of corporate and government borrowers, including insurance companies. To meet competition, ASB offers a variety of savings and checking accounts at competitive rates, convenient business hours, convenient branch locations with interbranch deposit and withdrawal privileges at each branch and convenient automated teller machines. ASB also conducts advertising and promotional campaigns.

The primary factors in competing for first mortgage and other loans are interest rates, loan origination fees and the quality and range of lending products and services offered. Competition for origination of first mortgage loans comes primarily from mortgage banking and brokerage firms, commercial banks, other savings institutions, insurance companies and real estate investment trusts. ASB believes that it is able to compete for such loans primarily through the competitive interest rates and loan fees it charges, the types of mortgage loan programs it offers and the efficiency and quality of the services it provides its borrowers and the real estate business community.

In 2002, ASB began implementing a strategic plan to move from its traditional position as a thrift institution, focused on retail banking and residential mortgages, to a full-service community bank. To make the shift, ASB continued to build its business and commercial real estate lines of business in 2002. The origination of business and commercial real estate loans involves risks different from those associated with originating residential real estate loans. For example, the sources and level of competition may be different and credit risk is generally higher than for mortgage loans. These different risk factors are considered in the underwriting and pricing standards established by ASB for its business and commercial real estate loans.

In September 2002, ASB launched its STAR initiative (Strategic & Tactical Alignment of Resources), in which four of its lines of business—Retail Banking, Mortgage Banking, Commercial Real Estate and Commercial Banking—began implementing changes intended to increase profitability and enhance customer service.

There has been significant bank and thrift merger activity in Hawaii. Management cannot predict the impact, if any, of these mergers on the Company’s future competitive position, results of operations, financial condition or liquidity.

Credit Unions. The 1934 Federal Credit Union Act states that credit union membership “shall be limited to groups having a common bond of occupation or association” or to groups in a well-defined geographical area. In 1982, the National Credit Union Administration expanded its definition of “common bond” to allow “multiple common bonds”—i.e., small businesses that lacked enough workers to form their own credit unions were allowed to join existing credit unions so long as each group of employees had its own “bond.” In February 1998, the Supreme Court decided that

this expanded definition of “common bond” was impermissible, holding that the 1934 law required all members of a credit union to share a single common bond. In August 1998, the Credit Union Membership Access Act became law, which, among other things, amended the 1934 law to retroactively authorize credit union membership based on multiple common bonds, as long as each of the relevant groups has (with some exceptions) fewer than 3,000 members. The Credit Union Membership Access Act also facilitates the ability of insured credit unions to convert to mutual savings banks or savings associations, and requires that insured credit unions meet capital standards similar to those enacted for banks and thrifts in 1991.

In December 1998, the National Credit Union Administration adopted final rules to implement the Credit Union Membership Access Act. The new rules appear to favor the creation of larger credit unions by facilitating the merger of credit unions with fewer than 3,000 members. Under a Regulatory Flexibility Program that went into effect on March 1, 2002, the National Credit Union Administration allowed certain credit unions to expand the services offered to members. It is too early to evaluate whether these developments will result in increased competition for ASB by credit unions.

See “Certain factors that may affect future results and financial condition—Bank—Regulation of ASB—Federal Thrift Charter” in HEI’s MD&A for a discussion of the Gramm-Leach-Bliley Act of 1998.

Other

HEI Investments, Inc.

HEI Investment Corp. (HEIIC), incorporated in May 1984 primarily to make passive investments in corporate securities and other long-term investments, changed its name to HEI Investments, Inc. (HEIII) in January 2000. HEIII is not an “investment company” under the Investment Company Act of 1940 and has no direct employees. In February 2000, HEIII became a subsidiary of HEIPC.

HEIII’s long-term investments currently consist primarily of investments in leveraged leases. Since 1985, HEIII (then called HEIIC) has had a 15% ownership interest in an 818 MW coal-fired generating unit in Georgia, which is subject to a leveraged lease agreement. In 1987, HEIIC purchased commercial buildings on leasehold properties located in the continental United States, along with the related lease rights and obligations. These leveraged, purchase-leaseback investments include two major buildings housing operations of Hershey Foods in Pennsylvania and five supermarkets leased to The Kroger Co. in various states. HEIII’s investments in leveraged leases are accounted for in the Company’s continuing operations. For a discussion of HEIII’s former ownership interest in EPHE Philippines Energy Company, Inc. (EPHE), see “Discontinued operations.”

HEI Properties, Inc.

HEIDI Real Estate Corp., originally a subsidiary of HEIDI, was formed in February 1998. In September 1999, its name was changed to HEIPI and HEIDI transferred ownership of HEIPI to HEI. HEIPI currently holds primarily venture capital investments. As of December 31, 2003, HEIPI’s venture capital investments (in companies based in Hawaii and the U.S. mainland) amounted to $3.6 million.

The Old Oahu Tug Service, Inc.

On November 10, 1999, HTB changed its name to TOOTS. Prior to that date, HTB (a former maritime transportation company) was the parent of YB (a regulated interisland cargo carrier). In November 1999, HTB sold substantially all of its operating assets and the stock of YB and ceased maritime freight transportation operations. TOOTS currently administers certain employee and retiree-related benefits programs and monitors matters related its former operations and the operations of its former subsidiary.

Discontinued operations

For information concerning the Company’s discontinued international power operations formerly conducted by HEIPC and its subsidiaries and its discontinued residential real estate development business formerly conducted by MPC and its subsidiaries, see “Certain factors that may affect future results and financial condition—Consolidated—Discontinued operations and asset dispositions” in HEI’s MD&A and Note 13 to HEI’s Consolidated Financial Statements.

On March 6, 2000, a subsidiary of HEIII, HEIPC Philippines Holding Co., Inc., acquired a 50% interest in EPHE Philippines Energy Company, Inc. (EPHE), which was the owner of approximately 91.7% of the common stock of East Asia Power Resources Corporation (EAPRC), a Philippines holding company primarily engaged in the electric

generation business in Manila and Cebu. The Company wrote off this investment as of December 31, 2000 and subsequently classified the write-off in discontinued operations. Subsequently HEIPC Philippines Holding Co., Inc. was dissolved and thereafter the capital stock it held in EPHE at the time of the dissolution was cancelled pursuant to an EPHE capital stock reduction approved by the Philippine Securities and Exchange Commission.

The Company’s loss of its investment in EAPRC of approximately $90 million was recognized in 2000 for financial reporting purposes (including an income tax benefit of $35 million) and was included in HEI’s 2001 income tax return as an ordinary loss. In 2002, HEI requested that the Internal Revenue Service (IRS) concur with HEI’s position that the loss was deductible against the operating income of its other operating subsidiaries. On January 6, 2004, the IRS signed a closing agreement accepting HEI’s treatment of the write-off in 2000 of its indirect investment in EAPRC as an ordinary loss for federal corporate income tax purposes in its 2001 tax return.

Regulation and other matters

Holding company regulation. HEI and HECO are holding companies within the meaning of the Public Utility Holding Company Act of 1935 (1935 Act). However, under current rules and regulations, they are exempt from the comprehensive regulation of the SEC under the 1935 Act except for Section 9(a)(2) (relating to the acquisition of securities of other public utility companies) through compliance with the requirement that they file annually Form U-3A-2 under the 1935 Act for holding companies which own utility businesses that are intrastate in character. The exemption afforded HEI and HECO may be revoked if the SEC finds that such exemption “may be detrimental to the public interest or the interest of investors or consumers.” HEI and HECO may own or have interests in foreign utility operations without adversely affecting this exemption so long as the requirements of other exemptions under the 1935 Act are satisfied. In connection with HEIPC’s now-discontinued foreign electric utility operations, HEI had obtained the PUC certification which is a prerequisite to obtaining an exemption for foreign utility operations and to the Company’s maintenance of its exemption under the 1935 Act if it acquires such ownership interests. In 1996, HEI filed with the SEC a Form U-57, “Notification of Foreign Utility Company Status,” on behalf of HEI Power Corp. Guam (for the HEIPC Group’s Guam project, which has now been sold). In 1998, HEI filed two Form U-57’s on behalf of Baotou Tianjiao Power Co., Ltd. (for the HEIPC Group’s China project, which investment has been written off) and on behalf of Cagayan Electric Power & Light Co., Inc. (for HEIPC’s indirect subsidiary’s investment in that entity, which subsidiary has now been sold). In March 2000, HEI filed a Form U-57 on behalf of EAPRC (for the HEIPC Group’s investment in that entity). With the discontinuance of HEIPC’s international power operations, no further Form U-57 filings are contemplated.

Legislation has been introduced in Congress in the past that would repeal the 1935 Act, leaving the regulation of utility holding companies to be governed by other federal and state laws. Management cannot predict if similar legislation will be proposed or enacted in the future or the final form it might take.

HEI is subject to an agreement entered into with the PUC (the PUC Agreement) when HECO became a subsidiary of HEI. The PUC Agreement, among other things, requires HEI to provide the PUC with periodic financial information and other reports concerning intercompany transactions and other matters. It prohibits the electric utilities from loaning funds to HEI or its nonutility subsidiaries and from redeeming common stock of the electric utility subsidiaries without PUC approval. Further, the PUC could limit the ability of the electric utility subsidiaries to pay dividends on their common stock. See “Restrictions on dividends and other distributions” and “Electric utility regulation” (regarding the PUC review of the relationship between HEI and HECO).

As a result of the acquisition of ASB, HEI and HEIDI are subject to OTS registration, supervision and reporting requirements as savings and loan holding companies. In the event the OTS has reasonable cause to believe that the continuation by HEI or HEIDI of any activity constitutes a serious risk to the financial safety, soundness, or stability of ASB, the OTS is authorized under the Home Owners’ Loan Act of 1933, as amended, to impose certain restrictions in the form of a directive to HEI and any of its subsidiaries, or HEIDI and any of its subsidiaries. Such possible restrictions include limiting (i) the payment of dividends by ASB; (ii) transactions between ASB, HEI or HEIDI, and the subsidiaries or affiliates of ASB, HEI or HEIDI; and (iii) the activities of ASB that might create a serious risk that the liabilities of HEI and its other affiliates, or HEIDI and its other affiliates, may be imposed on ASB. Theoretically, this authority would allow the OTS to prohibit dividends, limit affiliate transactions or otherwise restrict activities as a result of losses suffered by HEI, HEIDI or their other subsidiaries, and thus conceivably may

be an indirect means of limiting affiliations between ASB and affiliates engaged in nonfinancial activities. See “Restrictions on dividends and other distributions.”

OTS regulations also generally prohibit savings and loan holding companies and their nonthrift subsidiaries from engaging in activities other than those which are specifically enumerated in the regulations. Such restrictions, if applicable to HEI and HEIDI, would significantly limit the kinds of activities in which HEI and HEIDI and their subsidiaries may engage. However, the OTS regulations provide for an exemption which is available to HEI and HEIDI if ASB satisfies the qualified thrift lender (QTL) test discussed below. See “Bank regulation—Qualified thrift lender test.” ASB must continue to meet the qualified thrift lender test in order to avoid restrictions on the activities of HEI and HEIDI and their subsidiaries. ASB met the QTL test at all times during 2003, but the failure of ASB to satisfy the QTL test in the future could result in a need to divest ASB. If such divestiture were to be required, federal law limits the entities that might be eligible to acquire ASB.

OTS-regulated thrifts must file a quarterly Thrift Financial Report to provide the OTS with specific information. Effective with the March 31, 2004 TRF, OTS will require greater detail concerning (i) holding companies such as HEI and HEIDI and (ii) transactions with affiliates. ASB has not yet analyzed the additional costs of providing the more detailed information.

On February 10, 2004, OTS issued a notice of proposed rule making whereby the hourly fees charged by OTS in connection with OTS’ examinations of savings and loan holding companies would be replaced by payment to OTS of a semi-annual assessment of the top-tier holding company in the holding company structure. For the HEI companies, that would be HEI itself. The assessment would consist of a base assessment amount (which OTS is proposing as $3,000) plus additional components based on the risk or complexity of the holding company’s business (which would in turn would be based on the holding company’s OTS risk classification and total consolidated assets), its organizational form, and its condition based on the most recent OTS examination rating assigned to the holding company. OTS will separately assess as “conglomerates” a limited number of “large and complex enterprises”. It is too early to determine whether the assessments under the proposed rules, if implemented, would be more or less expensive to HEI than are the current examination fees.

HEI and HEIDI are prohibited, directly or indirectly, or through one or more subsidiaries, from (i) acquiring control of, or acquiring by merger or purchase of assets, another insured institution or holding company thereof, without prior written OTS approval; (ii) acquiring more than 5% of the voting shares of another savings association or savings and loan holding company which is not a subsidiary; or (iii) acquiring or retaining control of a savings association not insured by the FDIC. No director or officer of HEI or HEIDI, or person beneficially owning more than 25% of such holding company’s voting shares, may, except with the prior approval of the OTS, (a) also serve as a director, officer, or employee of any insured institution or (b) acquire control of any savings association not a subsidiary of such holding company.

ASB Realty Corporation, a subsidiary of ASB, is licensed as a nondepository financial services loan company under the Hawaii Code of Financial Institutions. As a result of its direct or indirect voting control of ASB Realty Corporation, each of HEI, HEIDI and ASB has registered as a “Financial Institution Holding Company” and an “Institution-Affiliated Party” under the Hawaii Code. As a Financial Institution Holding Company, HEI, HEIDI and ASB are subject to examination by the Hawaii Commissioner of Financial Institutions (Hawaii Commissioner) to determine whether their respective conditions or activities are jeopardizing the safety and soundness of ASB Realty Corporation’s operations. However, the Hawaii Commissioner is authorized to conduct such an examination only if the Hawaii Commissioner has good cause to believe that the holding company is experiencing financial adversity which might have a material negative impact on the safety and soundness of ASB Realty Corporation.

The Hawaii Commissioner has authority to issue a cease and desist order to ASB Realty Corporation, ASB, HEIDI and HEI, if, for example, the Commissioner has reasonable grounds to believe that such entity is violating or about to violate the Hawaii Code or is engaged in or about to engage in illegal, unauthorized, unsafe or unsound practices. In appropriate circumstances, the Commissioner may also have authority to order ASB Realty Corporation to correct any impairment of its capital and surplus and to prohibit ASB, HEIDI and HEI from participating in the affairs of ASB Realty Corporation.

Restrictions on dividends and other distributions. HEI is a legal entity separate and distinct from its various subsidiaries. As a holding company with no significant operations of its own, the principal sources of its funds are dividends or other distributions from its operating subsidiaries, borrowings and sales of equity. The rights of HEI and, consequently, its creditors and shareholders, to participate in any distribution of the assets of any of its subsidiaries is subject to the prior claims of the creditors and preferred stockholders of such subsidiary, except to the extent that claims of HEI in its capacity as a creditor are recognized.

The abilities of certain of HEI’s subsidiaries to pay dividends or make other distributions to HEI are subject to contractual and regulatory restrictions. Under the PUC Agreement, in the event that the consolidated common stock equity of the electric utility subsidiaries falls below 35% of total electric utility capitalization (including in capitalization the current maturities of long-term debt, but excluding short-term borrowings), the electric utility subsidiaries would be restricted, unless they obtained PUC approval, in their payment of cash dividends to 80% of the earnings available for the payment of dividends in the current fiscal year and preceding five years, less the amount of dividends paid during that period. The PUC Agreement also provides that the foregoing dividend restriction shall not be construed to relinquish any right the PUC may have to review the dividend policies of the electric utility subsidiaries. The consolidated common stock equity of HEI’s electric utility subsidiaries was 53% of their total capitalization (including in capitalization the current maturities of long-term debt, but excluding short-term borrowings) as of December 31, 2003. As of December 31, 2003, HECO and its subsidiaries had common stock equity of $944 million, of which approximately $449 million were not available for transfer to HEI without regulatory approval.

The ability of ASB to make capital distributions to HEI and other affiliates is restricted under federal law. Subject to a limited exception for stock redemptions that do not result in any decrease in ASB’s capital and would improve ASB’s financial condition, ASB is prohibited from declaring any dividends, making any other capital distribution, or paying a management fee to a controlling person if, following the distribution or payment, ASB would be deemed to be undercapitalized, significantly undercapitalized or critically undercapitalized. See “Bank regulation—Prompt corrective action.” All capital distributions are subject to an indication of no objection by the OTS. Also see Note 11 to HEI’s Consolidated Financial Statements.

HEI and its subsidiaries are also subject to debt covenants, preferred stock resolutions and the terms of guarantees that could limit their respective abilities to pay dividends. The Company does not expect that the regulatory and contractual restrictions applicable to HEI or its direct and indirect subsidiaries will significantly affect the operations of HEI or its ability to pay dividends on its common stock.

Electric utility regulation. The PUC regulates the rates, issuance of securities, accounting and certain other aspects of the operations of HECO and its electric utility subsidiaries. See the previous discussions under “Electric utility—Rates” and “Electric utility—Most recent rate requests,” and “Recent rate requests” and “Regulation of electric utility rates” in HECO’s MD&A.

Any adverse decision or policy made or adopted by the PUC, or any prolonged delay in rendering a decision, could have a material adverse effect on consolidated HECO’s and the Company’s financial condition, results of operations or liquidity.

The PUC has ordered the electric utility subsidiaries to develop plans for the integration of demand- and supply-side resources available to meet consumer energy needs efficiently, reliably and at the lowest reasonable cost. See the previous discussion under “Electric utility—Integrated resource planning and requirements for additional generating capacity.”

On December 30, 1996, the PUC issued an order instituting a proceeding to identify and examine the issues surrounding electric competition and to determine the impact of competition on the electric utility infrastructure in Hawaii. See “Competition” in HECO’s MD&A.

Certain transactions between HEI’s electric public utility subsidiaries (HECO, MECO and HELCO) and HEI and affiliated interests are subject to regulation by the PUC. All contracts (including summaries of unwritten agreements) made on or after July 1, 1988 of $300,000 or more in a calendar year for management, supervisory, construction, engineering, accounting, legal, financial and similar services and for the sale, lease or transfer of property between a public utility and affiliated interests must be filed with the PUC to be effective, and the PUC may issue cease and desist orders if such contracts are not filed. All such affiliated contracts for capital expenditures (except for real

property) must be accompanied by comparative price quotations from two nonaffiliates, unless the quotations cannot be obtained without substantial expense. Moreover, all transfers of $300,000 or more of real property between a public utility and affiliated interests require the prior approval of the PUC and proof that the transfer is in the best interest of the public utility and its customers. If the PUC, in its discretion, determines that an affiliated contract is unreasonable or otherwise contrary to the public interest, the utility must either revise the contract or risk disallowance of the payments for ratemaking purposes. In ratemaking proceedings, a utility must also prove the reasonableness of payments made to affiliated interests under any affiliated contract of $300,000 or more by clear and convincing evidence. An “affiliated interest” is defined by statute and includes officers and directors of a public utility, every person owning or holding, directly or indirectly, 10% or more of the voting securities of a public utility, and corporations which have in common with a public utility more than one-third of the directors of that public utility.

In January 1993, to address community concerns expressed at the time, HECO proposed that the PUC initiate a review of the relationship between HEI and HECO and the effects of that relationship on the operations of HECO. The PUC opened a docket and initiated such a review to determine whether the HEI-HECO relationship, HEI’s diversified activities, and HEI’s policies, operations and practices had resulted in or were having any negative effects on HECO, its electric utility subsidiaries and ratepayers. In May 1994, the PUC selected a consultant, Dennis Thomas and Associates, to perform the review. In early 1995, Dennis Thomas and Associates issued its report (the Thomas report) to the PUC. The Thomas report concluded that “on balance, diversification has not hurt electric ratepayers.” Other major findings were that (1) no utility assets have been used to fund HEI’s nonutility investments or operations, (2) management processes within the electric utilities operate without interference from HEI and (3) HECO’s access to capital did not suffer as a result of HEI’s involvement in nonutility activities and that diversification did not permanently raise or lower the cost of capital incorporated into the rates paid by HECO’s utility customers. The Thomas report also included a number of recommendations, most of which the Company has implemented. In December 1996, the PUC issued an order that adopted the Thomas report in its entirety, ordered HECO to continue to provide the PUC with status reports on its compliance with the PUC agreement (pursuant to which HEI became the holding company of HECO) and closed the investigation and proceeding. The PUC has not required that the Company implement all of the recommendations in the Thomas report. In the order, the PUC also stated that it adopted the recommendation of the DOD that HECO, MECO and HELCO present a comprehensive analysis of the impact that the holding company structure and investments in nonutility subsidiaries have on a case-by-case basis on the cost of capital to each utility in future rate cases and remove such effects from the cost of capital. The PUC has accepted, in subsequent MECO and HELCO rate cases, the presentations made by MECO and HELCO that there was no such impact in those cases. See also “Holding company regulation.”

HECO and its electric utility subsidiaries are not subject to regulation by the Federal Energy Regulatory Commission under the Federal Power Act, except under Sections 210 through 212 (added by Title II of PURPA and amended by the Energy Policy Act of 1992), which permit the Federal Energy Regulatory Commission to order electric utilities to interconnect with qualifying cogenerators and small power producers, and to wheel power to other electric utilities. Title I of PURPA, which relates to retail regulatory policies for electric utilities, and Title VII of the Energy Policy Act of 1992, which creates “exempt wholesale generators” (EWGs) as a category that is exempt from the 1935 Act and addresses transmission access, also apply to HECO and its electric utility subsidiaries. HECO and its electric utility subsidiaries are also required to file various financial and operational reports with the Federal Energy Regulatory Commission. The Company cannot predict the extent to which cogeneration, EWGs or transmission access will reduce its electrical loads, reduce its current and future generating and transmission capability requirements or affect its financial condition, results of operations or liquidity.

Because they are located in the State of Hawaii, HECO and its subsidiaries are exempt by statute from limitations set forth in the Powerplant and Industrial Fuel Act of 1978 on the use of petroleum as a primary energy source.

Bank regulation. ASB, a federally chartered savings bank, and its holding companies are subject to the regulatory supervision of the OTS and, in certain respects, the FDIC and the Hawaii Commissioner of Financial Institutions. See above under “Holding company regulation.” In addition, ASB must comply with Federal Reserve Board reserve requirements and OTS liquidity requirements. See “Liquidity and capital resources—Bank” in HEI’s MD&A.

Deposit insurance coverage. The Federal Deposit Insurance Act, as amended by the Federal Deposit Insurance Corporation Insurance Act of 1991 (FDICIA), and regulations promulgated by the FDIC, govern insurance coverage of deposit amounts. Generally, the deposits maintained by a depositor in an insured institution are insured to $100,000, with the amount of all deposits held by a depositor in the same capacity (even if held in separate accounts) aggregated for purposes of applying the $100,000 limit. For example, all deposits held in a depositor’s individual capacity are aggregated with each other but not with deposits maintained by such depositor and his or her spouse in a qualifying joint account, these latter joint deposits being separately insured to an aggregate of $100,000. An individual’s interest in deposits at the same institution in any combination of certain retirement accounts and employee benefit plans will be added together and insured up to $100,000 in the aggregate.

Institutions that are “well capitalized” under the FDIC’s prompt corrective action regulations are generally able to provide “pass-through” insurance coverage (i.e., insurance coverage that passes through to each owner/beneficiary of the applicable deposit) for the deposits of most employee benefit plans (i.e., $100,000 per individual participating, not $100,000 per plan). Consequently, the FDIC deposit insurance regulations require financial institutions to provide employee benefit plan depositors information, not otherwise available, on the institution’s capital category and whether “pass-through” deposit insurance is available. As of December 31, 2003, ASB was “well capitalized.”

Federal thrift charter. See “Certain factors that may affect future results and financial condition—Bank—Regulation of ASB—Federal Thrift Charter” in HEI’s MD&A.

Recent legislation. The Gramm-Leach-Bliley Act of 1998 (the Act) imposes on financial institutions an obligation to protect the security and confidentiality of its customers’ nonpublic personal information and, on February 1, 2001, the FDIC and OTS issued final guidelines for the establishment of standards for safeguarding such information effective from July 1, 2001. On August 12, 2003, the FDIC and OTS issued a request for comment on a proposed interagency guidance describing the regulatory agencies’ expectations that every financial institution develop a response program to protect against and address reasonably foreseeable risks associated with internal and external threats to the security of customer information maintained by the financial institution or its service providers. The Act also requires public disclosure of certain agreements entered into by insured depository institutions and their affiliates in fulfillment of the Community Reinvestment Act of 1977, and the filing of an annual report with the appropriate regulatory agencies. On January 10, 2001, the FDIC and the OTS issued final rules implementing these provisions of the Act, effective from April 1, 2001. Although the Act will continue to impose additional compliance costs on ASB, ASB believes that any ongoing compliance costs will not be significant.

The International Money Laundering Abatement and Financial Anti-Terrorism Act of 2001 (the 2001 Act), which is part of the USA Patriot Act, imposes on financial institutions a wide variety of additional obligations with respect to such matters as collecting information, monitoring relationships and reporting suspicious activities. Among other things, the 2001 Act requires the U.S. Treasury to issue regulations establishing minimum requirements for verifying the identity of persons seeking to open an account, maintaining records of the information used for such verification, and consulting lists of known or suspected terrorists or terrorist organizations. On May 9, 2003, various federal regulatory agencies including OTS jointly issued final rules requiring financial institutions to fully implement by October 1, 2003 a customer identification program. Additional compliance costs resulting from the final rules are not material. The 2001 Act also requires financial institutions to establish anti-money laundering programs and, with respect to correspondent and private banking accounts of non-U.S. persons, to implement appropriate due diligence policies to detect money laundering activities carried out through such accounts. ASB is monitoring the steps being taken by the regulatory agencies to implement these and other provisions of the 2001 Act.

Effective January 1, 2003, the OTS issued final regulations specifying the record keeping and confirmation requirements applicable to thrifts and their subsidiaries engaged in effecting securities transactions for customers, which will apply to one of ASB’s subsidiaries which effects securities transactions as an agent. However, ASB does not believe the new requirements will result in significant additional compliance costs.

Capital requirements. Under the Financial Institutions Reform, Recovery, and Enforcement Act of 1989 (FIRREA), the OTS has set three capital standards for thrifts, each of which must be no less stringent than those applicable to national banks. As of December 31, 2003, ASB was in compliance with all of the minimum standards with a core capital ratio of 7.0% (compared to a 4.0% requirement), a tangible capital ratio of 7.0% (compared to a 1.5% requirement) and total risk-based capital ratio of 15.6% (based on risk-based capital of $491.2 million, $239.2 million in excess of the 8.0% requirement).

Effective April 1, 1999, the OTS revised its risk-based capital standards as part of the effort by the OTS, FDIC, the Board of Governors of the Federal Reserve System and the Office of the Comptroller of the Currency to implement the provisions of the Riegle Community Development and Regulatory Improvement Act of 1994, which requires these agencies to work together to make uniform their respective regulations and guidelines implementing common statutory or supervisory policies. These OTS revisions affect the risk-based capital treatment of: (1) construction loans on presold residential properties; (2) junior liens on 1- to 4-family residential properties; (3) investments in mutual funds; and (4) the core capital leverage ratio for institutions which do not have a composite rating of “1” under the Uniform Financial Institution Rating System (i.e., the CAMELS rating system). Under the new rules, an institution with a composite rating of “1” under the CAMELS rating system must maintain core capital in an amount equal to at least 3% of adjusted total assets. All other institutions must maintain a minimum core capital of 4% of adjusted total assets, and higher capital ratios may be required if warranted by particular circumstances. As of December 31, 2003, ASB met the applicable minimum core capital requirement of the revised OTS regulations.

Effective July 1, 2002, new OTS rules eliminated the requirement that one-to-four-family residential mortgage loans have a maximum loan-to-value ratio of not more than 80% at origination in order to qualify for a 50% risk rate in calculating capital charges. The new rules conform OTS practice to the more flexible federal Interagency Guidelines for Real Estate Lending by requiring that qualifying mortgage loans be underwritten in accordance with prudent underwriting standards, including standards (i) relating the amortized principal balance of the loan to the value of the property at origination and (ii) establishing acceptable forms of credit enhancement for loans exceeding loan-to-value thresholds. In addition, the new rule eliminates the former requirement that a thrift must deduct from total capital the portion of a land loan or non-residential construction loan that exceeds an 80% loan-to-value ratio.

On January 1, 2002, new OTS regulations went into effect with respect to the regulatory capital treatment of recourse obligations, residual interests, direct credit substitutes and asset- and mortgage-backed securities. The revised capital regulations affect institutions that (1) securitize and sell their assets but retain a residual interest or provide recourse arrangements; (2) credit enhance third party assets; or (3) invest in third party asset- and mortgage-backed securities. Recourse obligations, residual interests, direct credit substitutes and asset- and mortgage-backed securities are now risk-weighted based on their credit agency rating. The new regulations have had a slight positive impact on ASB’s risk-based capital.

On July 1, 2002, new regulations went into effect which reduced the risk rating under the OTS’ risk-based capital rules for claims on and claims guaranteed by “qualifying securities firms,” such as broker-dealers which are registered with the SEC and comply with net capital requirements, from 100% to 20%, and to zero percent for certain claims on qualifying securities firms that are collateralized with, for example, cash deposits or securities issued by or guaranteed by the U.S.

Current OTS risk-based capital requirements are based on an internationally agreed framework for capital measurement (the “1988 Accord”) that was developed by the Basel Committee on Banking Supervision (“BCBS”). On April 29, 2003, BCBS released for comment proposed revisions to the 1988 Accord. BCBS expects to implement revisions to the 1998 Accord effective December 31, 2006. On August 4, 2003, the federal financial institution regulatory agencies, including OTS, issued an advance notice of proposed rule making (“Advance Notice”) soliciting comment on possible changes to U.S. risk-based capital requirements in light of the BCBS proposed revisions to the 1988 Accord. The Advance Notice describes the purpose of the BCBS proposal as making risk-based capital requirements more risk sensitive than are the requirements of the 1988 Accord and current U.S. (including OTS) rules implementing the 1988 Accord. The possible changes to the U.S. rules described in the Advance Notice are greatest with respect to financial institutions with banking and thrift assets of $250 billion or more or total on-balance-sheet foreign exposure of $10 billion or more. However, impacts on smaller financial institutions such as ASB are possible. ASB will continue to monitor regulatory developments.

Affiliate transactions. Significant restrictions apply to certain transactions between ASB and its affiliates, including HEI and its direct and indirect subsidiaries. FIRREA significantly altered both the scope and substance of such limitations on transactions with affiliates and provided for thrift affiliate rules similar to, but more restrictive than, those applicable to banks. On November 27, 2002, the Federal Reserve Board (FRB) issued Regulation W, effective April 1, 2003 which, generally speaking, unifies in one public document FRB’s prior interpretations of the statutory provisions governing affiliate transactions. Although thrifts are excluded from Regulation W, on December 12, 2002, OTS issued an interim final rule, also effective April 1, 2003, which applies Regulation W to thrifts with modifications appropriate to the greater restrictions under which thrifts operate. Most of these greater restrictions were carried over into the OTS’ final rule, which became effective November 6, 2003. For example, ASB is prohibited from making any loan or other extension of credit to an entity affiliated with ASB unless the affiliate is engaged exclusively in activities which the Federal Reserve Board has determined to be permissible for bank holding companies. There are also various other restrictions which apply to certain transactions between ASB and certain executive officers, directors and insiders of ASB. ASB is also barred from making a purchase of or any investment in securities issued by an affiliate, other than with respect to shares of a subsidiary of ASB.

Financial Derivatives and Interest Rate Risk. In 1996, the Board of Governors of the Federal Reserve System, the FDIC and the Office of the Comptroller of the Currency issued a joint agency policy statement to bankers to provide guidance on sound practices for managing interest rate risk. However, the OTS has elected not to pursue a standardized policy towards interest rate risk and investment and derivatives activities with the other federal banking regulators.

On December 1, 1998, the OTS issued final rules on financial derivatives, effective January 1, 1999. The OTS views these final rules as consistent with, although more detailed than, the 1996 joint policy statement. The purpose of these rules is to update the OTS rules on financial derivatives, which had remained virtually unchanged for over 15 years. Most significantly, the new rules address interest rate swaps, a derivative instrument commonly used by thrifts to manage interest rate risk which was not addressed in the prior OTS rules. Currently ASB does not use interest rate swaps to manage interest rate risk, but may do so in the future. Generally speaking, the new rules permit thrifts to engage in transactions involving financial derivatives to the extent these transactions are otherwise authorized under applicable law and are safe and sound. The new rules have required ASB to revise its internal procedures for handling financial derivative transactions, including increased involvement of the ASB Board of Directors.

Concurrently with the issuance of the new rules of financial derivative transactions, the OTS also adopted on December 1, 1998 Thrift Bulletin 13a (TB 13a) for purpose of providing guidance on the management of interest rate risks, investment securities and derivatives activities. TB 13a also describes the guidelines OTS examiners will use in assigning the “Sensitivity to Market Risk” component rating under the Uniform Financial Institutions Rating System (i.e., the CAMELS rating system). TB 13a became effective on December 1, 1998, and replaced several previous Thrift Bulletins dealing with interest rate risk and securities activities.

Effective July 1, 2002, new OTS rules eliminated the interest rate risk component of the OTS’s risk-based capital regulations. As a result of waivers granted by the Acting OTS Director, these regulations had never gone into effect and the OTS had relied instead on the interest rate risk guidelines of TB 13a, which will continue in effect. The OTS will apply a 100% risk weight to all stripped, mortgage-related securities regardless of issuer or guarantor.

TB 13a updates the OTS’s minimum standards for thrift institutions’ interest rate risk management practices with regard to board-approved risk limits and interest rate risk measurement systems, and makes several significant changes. First, under TB 13a, institutions no longer set board-approved limits or provide measurements for the plus and minus 400 basis point interest rate scenarios prescribed by the original TB 13. TB 13a also changes the form in which those limits should be expressed. Second, TB 13a provides guidance on how the OTS will assess the prudence of an institution’s risk limits. Third, TB 13a raises the size threshold above which institutions should calculate their own estimates of the interest rate sensitivity of Net Portfolio Value (NPV) from $500 million to $1 billion in assets. Fourth, TB 13a specifies a set of desirable features that an institution’s risk measurement methodology should utilize. Fifth, TB 13a provides an extensive discussion of “sound practices” for interest rate risk management.

TB 13a also contains guidance on thrifts’ investment and derivatives activities by describing the types of analysis institutions should perform prior to purchasing securities or financial derivatives. TB13a also provides

guidelines on the use of certain types of securities and financial derivatives for purposes other than reducing portfolio risk.

Finally, TB 13a provides detailed guidelines for implementing part of the Notice announcing the revision of the CAMELS rating system, published by the Federal Financial Institutions Examination Council. That publication announced revised interagency policies that, among other things, established the Sensitivity to Market Risk component rating (the “S” rating). TB 13a provides quantitative guidelines for an initial assessment of an institution’s level of interest rate risk. Examiners have broad discretion in implementing those guidelines. It also provides guidelines concerning the factors examiners consider in assessing the quality of an institution’s risk management systems and procedures.

Liquidity. Effective July 18, 2001, the OTS removed the regulation that required a savings association to maintain an average daily balance of liquid assets of at least 4% of their liquidity base and retained a provision requiring a savings association to maintain sufficient liquidity to ensure safe and sound operations. ASB’s principal sources of liquidity are customer deposits, wholesale borrowings, the sale of mortgage loans into the 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 by the FHLB to borrow up to 35% of assets to the extent it provides qualifying collateral and holds sufficient FHLB stock. At December 31, 2003, 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 December 31, 2003, ASB had commitments to borrowers for undisbursed loan funds and unused lines and letters of credit of $0.8 billion. Management believes ASB’s current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.

Supervision. The adoption of FDICIA subjected the banking and thrift industries to heightened regulation and supervision. FDICIA made a number of reforms addressing the safety and soundness of the deposit insurance system, supervision of domestic and foreign depository institutions and improvement of accounting standards. FDICIA also limited deposit insurance coverage, implemented changes in consumer protection laws and called for least-cost resolution and prompt corrective action with regard to troubled institutions.

Pursuant to FDICIA, the federal banking agencies promulgated regulations which apply to the operations of ASB and its holding companies. Such regulations address, for example, standards for safety and soundness, real estate lending, accounting and reporting, transactions with affiliates, and loans to insiders.

Prompt corrective action. FDICIA establishes a statutory framework that is triggered by the capital level of a savings association and subjects it to progressively more stringent restrictions and supervision as capital levels decline. The OTS rules implement the system of prompt corrective action. In particular, the rules define the relevant capital measures for the categories of “well capitalized”, “adequately capitalized”, “undercapitalized”, “significantly undercapitalized” and “critically undercapitalized.”

A savings association that is “undercapitalized” or “significantly undercapitalized” is subject to additional mandatory supervisory actions and a number of discretionary actions if the OTS determines that any of the actions is necessary to resolve the problems of the association at the least possible long-term cost to the SAIF. A savings association that is “critically undercapitalized” must be placed in conservatorship or receivership within 90 days, unless the OTS and the FDIC concur that other action would be more appropriate. As of December 31, 2003, ASB was “well-capitalized.”

Interest rates. FDIC regulations restrict the ability of financial institutions that are undercapitalized to offer interest rates on deposits that are significantly higher than the rates offered by competing institutions. As of December 31, 2003, ASB was “well capitalized” and thus not subject to these interest rate restrictions.

Qualified thrift lender test. FDICIA amended the QTL test provisions of FIRREA by reducing the percentage of assets thrifts must maintain in “qualified thrift investments” from 70% to 65%, and changing the computation period to require that the percentage be reached on a monthly average basis in 9 out of the previous 12 months. The 1997 Omnibus Appropriations Act expanded the types of loans that constitute “qualified thrift investments” from the traditional category of housing-related loans to include small business loans, education loans, loans made through

credit card accounts, as well as a basket of other consumer loans and certain other types of assets not to exceed 20% of total assets. Savings associations that fail to satisfy the QTL test by not holding the required percentage of “qualified thrift investments” are subject to various penalties, including limitations on their activities. Failure to satisfy the QTL test would also bring into operation restrictions on the activities that may be engaged in by HEI, HEIDI and their other subsidiaries and could effectively result in the required divestiture of ASB. At all times during 2003, ASB was in compliance with the QTL test. As of December 31, 2003, 88.7% of ASB’s portfolio assets was “qualified thrift investments.” See “Holding company regulation.”

Federal Home Loan Bank System. ASB is a member of the FHLB System which consists of 12 regional FHLBs. The FHLB System provides a central credit facility for member institutions. Historically, the FHLBs have served as the central liquidity facilities for savings associations and sources of long-term funds for financing housing. The FHLB may only make long-term advances to ASB for the purpose of providing funds for financing residential housing. At such time as an advance is made to ASB or renewed, it must be secured by collateral from one of the following categories: (1) fully disbursed, whole first mortgages on improved residential property, or securities representing a whole interest in such mortgages; (2) securities issued, insured or guaranteed by the U.S. Government or any agency thereof; (3) FHLB deposits; and (4) other real estate-related collateral that has a readily ascertainable value and with respect to which a security interest can be perfected. The aggregate amount of outstanding advances secured by such other real estate-related collateral may not exceed 30% of ASB’s capital.

As a result of the Gramm-Leach-Bliley Act, each regional FHLB is required to formulate and submit for Federal Housing Finance Board (Board) approval a plan to meet new minimum capital standards to be promulgated by the Board. The Board issued the final regulations establishing the new minimum capital standards on January 30, 2001. As mandated by Gramm-Leach-Bliley, these regulations require each FHLB to maintain a minimum total capital leverage ratio of 5% of total assets and include risk-based capital standards requiring each FHLB to maintain permanent capital in an amount sufficient to meet credit risk and market risk. In June 2001, the FHLB of Seattle formulated a capital plan to meet these new minimum capital standards, which plan was submitted to and approved by the Board. The capital plan requires ASB to own capital stock in the FHLB of Seattle in an amount equal to the total of 3.5% of the FHLB of Seattle’s advances to ASB plus the greater of (i) 5% of the outstanding balance of loans sold to the FHLB of Seattle by ASB or (ii) 0.75% of ASB’s mortgage loans and pass through securities. At December 31, 2003, ASB was required under the capital plan to own capital stock in the FHLB of Seattle in the amount of $64.8 million and owned capital stock in the amount of $94.6 million, or $29.8 million in excess of the requirement. Under the capital plan, stock in the FHLB of Seattle is subject to a 5-year notice of redemption. This 5-year notice period has an adverse but immaterial effect on ASB’s liquidity.

Community Reinvestment. In 1977, Congress enacted the Community Reinvestment Act (CRA) to ensure that banks and thrifts help meet the credit needs of their communities, including low- and moderate-income areas, consistent with safe and sound lending practices. The OTS will consider ASB’s CRA record in evaluating an application for a new deposit facility, including the establishment of a branch, the relocation of a branch or office, or the acquisition of an interest in another bank or thrift. On February 6, 2004, the OTS issued a notice of proposed rule making proposing that certain discriminatory, illegal or abusive credit practices would adversely affect an institution’s CRA rating. ASB currently holds an “outstanding” CRA rating.

Other laws. ASB is subject to federal and state consumer protection laws which affect lending activities, such as the Truth-in-Lending Law, the Truth-in-Savings Act, the Equal Credit Opportunity Act, the Real Estate Settlement Procedures Act and several federal and state financial privacy acts. These laws may provide for substantial penalties in the event of noncompliance. ASB believes that its lending activities are in compliance with these laws and regulations.

Environmental regulation. HEI and its subsidiaries are subject to federal and state statutes and governmental regulations pertaining to water quality, air quality and other environmental factors.

HECO, HELCO and MECO, like other utilities, are all subject to periodic inspections by regulatory agencies. These inspections may result in the identification of items needing correction or other action. When the corrective or other necessary action is taken, no further regulatory action is expected. Except as otherwise disclosed in this report (including in incorporated documents), the Company believes that each subsidiary has taken appropriate

action on environmental conditions requiring action and that as a result of such actions, the environmental condition will not have a material adverse effect on consolidated HECO or the Company.

Water quality controls. As part of the process of generating electricity, water used for condenser cooling of the electric utility subsidiaries’ steam electric generating stations is discharged into ocean waters or into underground injection wells. The subsidiaries are periodically required to obtain permits from the DOH in order to be allowed to discharge the water, including obtaining permit renewals for existing facilities and new permits for new facilities. The electric utility subsidiaries must obtain National Pollutant Discharge Elimination System (NPDES) permits from the DOH to allow wastewater and storm water discharges into state and federal waters for their coastal generating stations and Underground Injection Control (UIC) permits for wastewater discharge to underground injection wells for one MECO facility and several HELCO facilities.

In 2003, the DOH conducted NPDES permit compliance inspections at HELCO’s Shipman generating station, HECO’s Honolulu generating station, and HECO’s Waiau generating station. All facilities were found to be in compliance with NPDES permit requirements.

Section 316(b) of the Clean Water Act requires that the EPA ensure that the location, design, construction and capacity of power plant cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts. On February 16, 2004, the EPA Administrator signed a final regulation implementing Section 316(b). The regulation establishes location, design, construction and capacity standards for existing cooling water intake systems that use large amounts of cooling water. Strong technology-based performance standards apply unless a facility shows that these standards will result in very high costs or little environmental benefit at the facility site. EPA estimates that the rule affects approximately 550 facilities across the nation. The new rule, which is currently pending publication in the Federal Register, becomes effective 60 days after publication and will apply to HECO’s Kahe, Waiau and Honolulu generating stations. HECO will have 3.5 years from the effective date of the rule to demonstrate compliance. HECO is currently preparing and will conduct a monitoring program and cost-benefit analysis to demonstrate that HECO’s existing intake systems have minimal environmental impacts. Concurrently, HECO will evaluate alternative compliance mechanisms allowed by the rule, some of which could entail significant costs to implement. HECO has not yet budgeted any such costs in its five-year capital expenditures forecast.

In 1994, HELCO constructed two UIC-permitted injection wells designed to receive wastewater from CT-4 and CT-5 once they become operational, as well as from other existing activities at the Keahole power plant. Although these wells were installed and the UIC permit issued, the associated piping connections to the wells were not made due to anticipation of the forthcoming CT-4 and CT-5 generation additions. In connection with the preconstruction stay originally issued for CT-4 and CT-5, HELCO registered the UIC wells as inactive. Because the land issue matter with CT-4 and CT-5 appeared to be resolved and construction activities resumed in May 2002, HELCO submitted an application to DOH to reactivate the UIC permit for these wells. This application was put on hold following an October 2002 order of the Circuit Court for the Third Circuit of Hawaii that again halted construction. Existing wastewater management activities did not require a UIC permit and were planned to be rerouted to the injection wells as a process improvement. After the Third Circuit Court vacated its construction stop order on November 12, 2003 (see Note 11 to HECO’s Consolidated Financial Statements), a request was submitted to the DOH to resume processing the UIC permit and the UIC permit was issued to HELCO in the first quarter of 2004.

In 2000, the EPA introduced new regulations that prohibit the construction of large capacity cesspools, many of which are regulated under the DOH’s UIC permitting program. All large capacity cesspools must be permanently closed by April 2005. Some alternatives to using large capacity cesspools include connecting to existing municipal sanitary sewer systems or installing large capacity septic treatment systems. HECO, MECO and HELCO are in the process of closing cesspools at the Kahe, Maalaea and Kahului generating stations and the Kanoelehua Base Yard. These cesspools will be replaced with septic tank treatment systems. All companies are on schedule to comply with the April 2005 deadline.

The Federal Oil Pollution Act of 1990 (OPA) governs actual or threatened oil releases in navigable U.S. waters (inland waters and up to three miles offshore) and waters of the U.S. exclusive economic zone (up to 200 miles to sea from the shoreline). In the event of an oil release to navigable U.S. waters, OPA establishes strict and joint and several liability for responsible parties for 1) oil removal costs incurred by the federal government or the state, and 2) damages to natural resources and real or personal property. Responsible parties include vessel owners and

operators of on-shore facilities. OPA imposes fines and jail terms ranging in severity depending on how the release was caused. OPA also requires that responsible parties submit certificates of financial responsibility sufficient to meet the responsible party’s maximum limited liability. HECO is currently involved in an ongoing investigation of the Honolulu Harbor area. (See Note 11 to HECO’s Consolidated Financial Statements.) Under the terms of the agreement for the sale of YB, HEI and TOOTS had certain environmental obligations arising from conditions existing prior to the sale of YB, including obligations with respect to the Honolulu Harbor investigation. In 2003, TOOTS paid $250,000 in full settlement of this environmental obligation. See Note 3 to HEI’s Consolidated Financial Statements.

EPA regulations under OPA also require that certain facilities that store petroleum prepare and implement Spill Prevention, Containment and Countermeasure (SPCC) Plans in order to prevent releases of petroleum to navigable waters of the U.S. HECO, HELCO and MECO facilities subject to the SPCC program are in compliance with these requirements. On July 17, 2002, EPA amended the SPCC regulations to include facilities, such as substations, that use (as opposed to store) petroleum products. HECO, HELCO and MECO have determined that the amended SPCC program applies to a number of their substations. By interim final rule issued January 9, 2003, the EPA amended the revised regulations, which required development of the SPCC plans for affected facilities by April 17, 2003, and implementation of the plans by October 18, 2003. Concurrently, the EPA proposed a rule to further extend compliance dates for the amended regulations by one year. On April 17, 2003, EPA issued its final rules that included an 18-month extension to the rule’s compliance dates. The longer time frame was intended to address concerns raised by the regulated community, and to avoid a potentially overwhelming number of individual extension requests. The new compliance dates are August 17, 2004, to amend an existing SPCC Plan, and February 18, 2005, to implement the Plan. Regulated facilities that start operations after August 16, 2002, through February 18, 2005, must prepare and implement an SPCC Plan by February 18, 2005. HECO, HELCO and MECO are currently developing SPCC plans for all facilities that are subject to the amended SPCC requirements.

Air quality controls. The generating stations of the utility subsidiaries operate under air pollution control permits issued by the DOH and, in a limited number of cases, by the EPA. The entire electric utility industry has been affected by the 1990 amendments to the Clean Air Act (CAA), changes to the National Ambient Air Quality Standard (NAAQS) for ozone, and adoption of a NAAQS for fine particulate matter. Further significant impacts may occur if currently proposed legislation, rules and standards are adopted. If the Clear Skies Bill is adopted as currently proposed, HECO, and to a lesser extent, HELCO and MECO will likely incur significant capital and operations and maintenance costs beginning one to two years after enactment. HECO boilers may be affected by the air toxics provisions (Title III) of the CAA when the Maximum Allowable Control Technology (MACT) emission standards are established for those units. HECO believes that, if adopted as currently proposed, the recent EPA proposal to regulate nickel emissions from oil-fired boilers may require significant capital investment for HECO’s steam generating units. The public comment period on the proposed rule ends on March 30, 2004.

CAA operating permits (Title V permits) have been issued for all affected generating units except for HELCO’s Keahole CT-2, for which a permit is currently pending. Initial and follow-up source tests in 1989 and 1990 for HELCO’s CT-2 generating unit indicated particulate emissions above permitted levels. Following analysis, HECO (on behalf of HELCO) proposed that the permitted particulate limit be increased. EPA concurred with the recommendation. HECO and HELCO worked with the DOH, the manufacturer and a consultant to determine an appropriate new emission limit for particulates as well as oxides of nitrogen. DOH prepared a draft permit incorporating the revised emission standards that was the subject of a public hearing on January 7, 2002. EPA is currently reviewing the draft permit and HELCO anticipates EPA’s approval. CT-2 continues to operate pending issuance of the revised permit. In 1998, HELCO settled two notice of violations (NOVs) issued by the DOH in 1992 and 1998 for non-compliance with emission limits during various periods from 1990 through 1997. CT-2 is currently operating within all existing permit limits by virtue of its having passed its annual source tests since 1997.

On September 5, 2003, MECO received a 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 and 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. On December 23, 2003, the DOH and MECO reached

a conditional settlement of the NOV, subject to public notice and a comment period, which ended on February 26, 2004 with no comments. The settlement consists of a Proposed Consent Order that requires MECO to come into full compliance with the opacity rules for the units by December 31, 2004 and to pay a penalty of approximately $0.8 million to the DOH. The Proposed Consent Order would resolve all civil liability of MECO to the DOH for all opacity violations from February 1, 1999 to December 31, 2004. MECO has made significant progress in reducing the number of opacity exceedances from Maalaea Units 12 and 13 and expects to achieve full compliance with the opacity regulations during the Proposed Consent Order period without having to incur significant additional costs. The Consent Order (in the proposed form) is expected to be executed in March 2004.

Hazardous waste and toxic substances controls. The operations of the electric utility and former freight transportation subsidiaries are subject to regulations promulgated by the EPA to implement the provisions of the Resource Conservation and Recovery Act (RCRA), the Superfund Amendments and Reauthorization Act and the Toxic Substances Control Act. In 2001, the DOH obtained primacy to operate state-authorized RCRA (hazardous waste) programs. The DOH’s state contingency plan and the State of Hawaii Environmental Response Law (ERL) rules were adopted in August 1995.

On both federal and state levels, RCRA provisions identify certain wastes as hazardous and set forth measures that must be taken in the transportation, storage, treatment and disposal of these wastes. Some wastes generated at steam electric generating stations possess characteristics that subject them to these EPA regulations. Since October 1986, all HECO generating stations have operated RCRA-exempt wastewater treatment units to treat potentially regulated wastes from occasional boiler waterside and fireside cleaning operations. Steam generating stations at MECO and HELCO also operate similar RCRA-exempt wastewater management systems.

The EPA issued a final regulatory determination on May 22, 2000, concluding that fossil fuel combustion wastes do not warrant regulation as hazardous under Subtitle C of RCRA. This determination retains (or maintains) the existing hazardous waste exemption for these types of wastes. It also allows for more flexibility in waste management strategies. The electric utilities’ waste characterization programs continue to demonstrate the adequacy of the existing treatment systems. Waste recharacterization studies indicate that treatment facility wastestreams are nonhazardous.

RCRA underground storage tank (UST) regulations require all facilities with USTs used for storing petroleum products to comply with costly leak detection, spill prevention and new tank standard retrofit requirements. All HECO, HELCO and MECO USTs currently meet these standards and continue in operation. In 2003, the DOH conducted UST compliance inspections at HECO’s Ward Avenue Complex, Koolau base yard and Waiau generating station, and at HELCO’s Kanoelehua base yard. All facilities were found to be in compliance with UST requirements.

The DOH conducted RCRA compliance inspections at HECO’s Ward Avenue Complex and MECOs’ Kahului Base Yard on October 3, 2003 and December 19, 2003, respectively. HECO addressed cited deficiencies at the Ward facility, while additional information is being prepared for submittal to the DOH for the Kahului Base Yard inspection. Neither facility anticipates enforcement action from the DOH. In October 2003, the DOH and EPA initiated separate investigations at HECO’s Waiau Generating Station for the alleged offsite transport, treatment and disposal of hydrochloric acid by a HECO contractor. As of February 13, 2004, HECO submitted responses to all DOH requests for information relating to this matter and HECO is currently awaiting a response from the DOH. A decision about possible enforcement action by the DOH is still pending. At this time, HECO anticipates that the EPA will not be pursuing separate enforcement action regarding this incident.

The Emergency Planning and Community Right-to-Know Act under Superfund Amendments and Reauthorization Act Title III requires HECO, MECO and HELCO to report potentially hazardous chemicals present in their facilities in order to provide the public with information on these chemicals so that emergency procedures can be established to protect the public in the event of hazardous chemical releases. All HECO, MECO and HELCO facilities are in compliance with applicable annual reporting requirements to the State Emergency Planning Commission, the Local Emergency Planning Committee and local fire departments. Since January 1, 1998, the steam electric industry category has been subject to Toxics Release Inventory (TRI) reporting requirements. HECO, MECO and HELCO have timely filed release reports since 1998. In November 2002, the Company identified several discrepancies in previous TRI reports and submitted corrected reports to the EPA in February and August 2003.

The Toxic Substances Control Act regulations specify procedures for the handling and disposal of polychlorinated biphenyls (PCB), a compound found in transformer and capacitor dielectric fluids. HECO, MECO and HELCO have instituted procedures to monitor compliance with these regulations. In addition, HECO and its subsidiaries have implemented a program to identify and replace PCB transformers and capacitors in the HECO system. In 1998, the EPA published the final rule on the PCB disposal amendments. The amended rule clarified certain procedures and provides some flexibility within the context of a complex regulatory program governing the use, handling and disposal of equipment and materials containing PCBs. The EPA believes that this rule will result in substantial cost savings to the regulated community while protecting against unreasonable risk of injury to health and the environment from exposure to PCBs. On October 21, 2003, HECO voluntarily notified the EPA of a minor one-year storage violation regarding a single drum containing PCB-contaminated debris. The EPA issued a warning letter to HECO on December 3, 2003. HECO subsequently provided the EPA with follow-up information to document the appropriate disposal of the drum. The EPA has indicated it will take no further enforcement action on this matter. All HECO, MECO and HELCO facilities are currently believed to be in compliance with PCB regulations.

The ERL, as amended, governs releases of hazardous substances, including oil, in areas within the state’s jurisdiction. Responsible parties under the ERL are jointly, severally and strictly liable for a release of a hazardous substance into the environment. Responsible parties include owners or operators of a facility where a hazardous substance comes to be located and any person who at the time of disposal of the hazardous substance owned or operated any facility at which such hazardous substance was disposed. The DOH issued final rules (or State Contingency Plan) implementing the ERL on August 17, 1995.

On July 30, 2002, personnel at MECO’s Maalaea Generating Station discovered a leak in an underground diesel fuel line. MECO immediately discontinued using the fuel line and notified the DOH of the release. MECO replaced the leaking fuel line with a temporary aboveground line and then constructed a new aboveground fuel line and concrete containment trough as a permanent replacement. MECO also notified the U.S. Fish & Wildlife Service (USFWS), which manages the Kealia Pond National Wildlife Refuge that is located south of the Maalaea facility. MECO constructed a sump at the point of the leak to remove fuel from the subsurface. To date, MECO has recovered over 11,600 gallons of diesel fuel from the estimated 19,000-gallon release. In addition, MECO has installed soil borings and groundwater monitoring wells to assess the vertical and horizontal impacts of the fuel release. The investigation indicates that limited free phase fuel migration has occurred beneath the Maalaea facility and in a small portion of the buffer zone immediately to its south. The buffer zone is undeveloped property owned by MECO that separates the Maalaea facility from the Wildlife Refuge. Although monitoring wells indicate diesel fuel likely migrated to a small portion of the Wildlife Refuge that shares a common boundary with the facility, wells installed in the Wildlife Refuge itself indicate that migration has not been significant in that area. As a precautionary measure, with the guidance and consent of the USFWS and the DOH, MECO installed an interception trench in the buffer zone and in a small part of the Wildlife Refuge. The interception trench is designed to capture and facilitate removal of any fuel migrating from the impacted areas and to act as a barrier to migration beyond the trench. Based on results of the latest monitoring study in December 2003, the interception trench continues to operate as designed. Based on the results of the subsurface investigation and the location and design of the interception trench, management believes that the risk of the fuel release affecting wildlife, sensitive wildlife habitat or the ocean, which lies approximately one-quarter mile south of the Maalaea facility, is minimal. MECO estimates that it will incur approximately $0.8 million to successfully remediate the impacts of the release, and expensed the $0.8 million in 2002.

HECO, HELCO and MECO, like other utilities, periodically identify leaking petroleum-containing equipment such as USTs, piping and transformers. In a few instances, small amounts of PCBs have been identified in the leaking equipment. Each subsidiary reports releases from such equipment 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 on the respective subsidiary or the Company.

ASB may be subject to the provisions of Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) and regulations promulgated thereunder. CERCLA imposes liability for environmental cleanup costs on certain categories of responsible parties, including the current owner and operator of a facility and prior owners or operators who owned or operated the facility at the time the hazardous substances were released or disposed.

CERCLA exempts persons whose ownership in a facility is held primarily to protect a security interest, provided that they do not participate in the management of the facility. Although there may be some risk of liability for ASB for environmental cleanup costs in the event ASB forecloses on, and becomes the owner of, property with environmental problems, the Company believes the risk is not as great for ASB as it may be for other depository institutions that have a larger portfolio of commercial loans.

Securities ratings

See “Liquidity and capital resources” in HEI’s MD&A for the Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HEI’s and HECO’s securities. These 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. These ratings reflect only the view of the applicable rating agency at the time the ratings are issued, from whom an explanation of the significance of such ratings may be obtained. There is no assurance that any such credit rating will remain in effect for any given period of time or that such rating will not be lowered, suspended or withdrawn entirely by the applicable rating agency if, in such rating agency’s judgment, circumstances so warrant. Any such lowering, suspension or withdrawal of any rating may have an adverse effect on the market price or marketability of HEI’s and/or HECO’s securities, which could increase the cost of capital of HEI and HECO. Neither HEI nor HECO management can predict future rating agency actions or their effects on the future cost of capital of HEI or HECO.

Revenue bonds are issued by the Department of Budget and Finance of the State of Hawaii for the benefit of HECO and its subsidiaries, but the source of their repayment are the unsecured obligations of HECO and its subsidiaries under loan agreements and notes issued to the Department, including HECO’s guarantees of its subsidiaries’ obligations. The payment of principal and interest due on all revenue bonds currently outstanding are insured either by MBIA Insurance Corporation, by Ambac Assurance Corporation, or by XL Capital Assurance, Inc. and the ratings of those bonds are based on the ratings of the obligations of the bond insurer rather than HECO.

Research and development

HECO and its subsidiaries expensed approximately $3.1 million, $2.8 million and $2.6 million in 2003, 2002 and 2001, respectively, for research and development. Contributions to the Electric Power Research Institute accounted for more than half of the expenses. There were also expenses in the areas of energy conservation, new technologies, environmental and emissions controls, and expenses for studies relative to technologies that are applicable or may be applicable in the future to HECO, its subsidiaries and their customers.

Employee relations

At December 31, 2003 and 2002, the Company had 3,197 and 3,220 full-time employees, respectively, as follows:


December 31	2003	2002
HEI	44	44
HECO and its subsidiaries	1,862	1,894
ASB and its subsidiaries	1,285	1,272
Other subsidiaries	6	10

	3,197	3,220

The employees of HEI and its direct and indirect subsidiaries, other than the electric utilities, are not covered by any collective bargaining agreement. Of the 1,862 full time employees of HECO and its subsidiaries at December 31, 2003 approximately 59% were covered by collective bargaining agreements. See “Collective bargaining agreements” in HECO’s MD&A.

ITEM 2.

PROPERTIES

HEI leases office space from a nonaffiliated lessor in downtown Honolulu under a lease that expires on March 31, 2006. HEI also subleases office space from HECO in downtown Honolulu. The properties of HEI’s subsidiaries are as follows:

Electric utility

See page 5 for the “Generation statistics” of HECO and its subsidiaries, including net generating and firm purchased capability, reserve margin and annual load factor.

The electric utilities’ overhead and underground transmission and distribution systems (with the exception of substation buildings and contents) have a replacement value roughly estimated at $2 billion and are uninsured because the amount of transmission and distribution system insurance available is limited and the premiums are extremely high.

Electric lines are located over or under public and nonpublic properties. See page 2 for a discussion of the nonexclusive franchises of HECO and subsidiaries. Most of the leases, easements and licenses for HECO’s, HELCO’s and MECO’s lines have been recorded.

HECO owns and operates three generating plants on the island of Oahu at Honolulu, Waiau and Kahe, with an aggregate net generating capability of 1,208.6 MW at December 31, 2003. The three plants are situated on HECO-owned land having a combined area of 535 acres and one 3 acre parcel of land under a lease expiring December 31, 2018. In addition, HECO owns a total of 123 acres of land on which substations, transformer vaults, distribution baseyards and the Kalaeloa cogeneration facility are located.

HECO owns overhead transmission lines, overhead distribution lines, underground cables, poles (fully owned or jointly owned) and steel or aluminum high voltage transmission towers. The transmission system operates at 46,000 volts and 138,000 volts. The total capacity of HECO’s transmission and distribution substations was 6,656,300-kilovoltamperes at December 31, 2003.

HECO owns buildings and approximately 11.5 acres of land located in Honolulu which houses its operating, engineering and information services departments and a warehousing center. It also leases an office building and certain office spaces in Honolulu. The lease for the office building expires in November 2004, with an option to further extend the lease to November 2014. The leases for certain office spaces expire on various dates through November 30, 2007 with options to extend to various dates through November 30, 2017.

HECO owns 19.2 acres of land at Barbers Point used to situate fuel oil storage facilities with a combined capacity of 970,700 barrels. HECO also owns fuel oil tanks at each of its plant sites with a total maximum usable capacity of 844,600 barrels.

HELCO owns and operates five generating plants on the island of Hawaii. These plants at Hilo (2), Waimea, Kona and Puna have an aggregate net generating capability of 146.1 MW as of December 31, 2003 (excluding a small run-of-river hydro unit and one small windfarm). The plants are situated on HELCO-owned land having a combined area of approximately 43 acres. HELCO also owns 6 acres of land in Kona, which is used for a baseyard, and one acre of land in Hilo, which houses its administrative offices. HELCO also leases 4 acres of land for its baseyard in Hilo under a lease expiring in 2030. The deeds to the sites located in Hilo contain certain restrictions which do not materially interfere with the use of the sites for public utility purposes. HELCO occupies 78 acres of land for the windfarm, pursuant to a long-term operating agreement.

MECO owns and operates two generating plants on the island of Maui, at Kahului and Maalaea, with an aggregate net generating capability of 229.2 MW as of December 31, 2003. The plants are situated on MECO-owned land having a combined area of 28.6 acres. MECO also owns fuel oil storage facilities at these sites with a total maximum usable capacity of 176,355 barrels. MECO owns two 1 MW stand-by diesel generators and a 6,000 gallon fuel storage tank located in Hana. MECO owns 65.7 acres of undeveloped land at Waena. The Waena land is currently being used for agricultural purposes by the former landowner under a license agreement dated November 19, 1996. The license agreement was originally scheduled to expire on December 31, 2004 but has been extended, effective January 1, 2005, on a month-to-month basis until the area is required for development by MECO for utility purposes, or February 28, 2006, whichever comes first.

MECO’s administrative offices and engineering and distribution departments are located on 9.1 acres of MECO-owned land in Kahului.

MECO also owns and operates smaller distribution systems, generation systems (with an aggregate net capability of 22.1 MW as of December 31, 2003) and fuel storage facilities on the islands of Lanai and Molokai, primarily on land owned by MECO.

Bank

ASB owns and leases several office buildings in downtown Honolulu and owns land and an operations center in the Mililani Technology Park on Oahu.

The following table sets forth the number of bank branches owned and leased by ASB by island:


	Number of branches
December 31, 2003	Owned	Leased	Total
Oahu	8	39	47
Maui	3	5	8
Kauai	3	3	6
Hawaii	2	4	6
Molokai	—	1	1

	16	52	68

At December 31, 2003, the net book value of branches and office facilities is approximately $43 million. Of this amount, $34 million represents the net book value of the land and improvements for the branches and office facilities owned by ASB and $9 million represents the net book value of ASB’s leasehold improvements. The leases expire on various dates from January 2004 through July 2033 and many of the leases have extension provisions.

ITEM 3.

LEGAL PROCEEDINGS

Except as identified in “Item 1. Business,” including information incorporated by reference in Item 1, there are no known material pending legal proceedings to which HEI or any of its subsidiaries is a party or to which any of their property is subject. Certain HEI subsidiaries are involved in ordinary routine litigation incidental to their respective businesses.

Discontinued operations

See Note 13 to HEI’s Consolidated Financial Statements.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

HEI and HECO:

During the fourth quarter of 2003, no matters were submitted to a vote of security holders of the Registrants.

EXECUTIVE OFFICERS OF THE REGISTRANT (HEI)

The following persons are, or may be deemed to be, executive officers of HEI. Their ages are given as of February 11, 2004 and their years of company service are given as of December 31, 2003. Officers are appointed to serve until the meeting of the HEI Board of Directors after the next Annual Meeting of Shareholders (which will occur on April 20, 2004) and/or until their successors have been appointed and qualified (or until their earlier resignation or removal). Company service includes service with an HEI subsidiary.


HEI Executive Officers		Business experience for past five years
Robert F. Clarke, age 61
Chairman of the Board, President and Chief Executive Officer		9/98 to date
Director		4/89 to date
(Company service: 16 years)

Eric K. Yeaman, age 36
Financial Vice President, Treasurer and Chief Financial Officer		01/03 to date
(Company service: 11 ½ months)
Eric K. Yeaman, prior to joining HEI, served as Chief Operating and Financial Officer of Kamehameha Schools from 4/02 to 1/03, Chief Financial Officer of Kamehameha Schools from 7/00 to 4/02 and Senior Manager – Audit and Advisory Services of Arthur Andersen LLP (at Arthur Andersen LLP from 9/89 to 7/00).

Peter C. Lewis, age 69
Vice President – Administration and Corporate Secretary		1/99 to date
(Company service: 35 years)

Charles F. Wall, age 64
Vice President and Corporate Information Officer		7/90 to date
(Company service: 13 years)

Andrew I. T. Chang, age 64
Vice President – Government Relations		4/91 to date
(Company service: 18 years)

Curtis Y. Harada, age 48
Controller		1/91 to date
(Company service: 14 years)


HEI Executive Officers		Business experience for past five years
(continued)

T. Michael May, age 57
President and Chief Executive Officer, Hawaiian Electric Company, Inc.		9/95 to date
Director, Hawaiian Electric Industries, Inc.		9/95 to date
Senior Vice President, Hawaiian Electric Industries, Inc.		9/95 to 4/01
(Company service: 11 years)

Constance H. Lau, age 51
President and Chief Executive Officer, American Savings Bank, F.S.B.		6/01 to date
Director, Hawaiian Electric Industries, Inc.		6/01 to date
Senior Executive Vice President and Chief Operating Officer, American Savings Bank, F.S.B.		12/99 to 6/01
Treasurer, Hawaiian Electric Industries, Inc.		4/89 to 10/99
(Company service: 19 years)

HEI’s executive officers, with the exception of Charles F. Wall and Andrew I. T. Chang, are also officers and/or directors of one or more of HEI’s subsidiaries. Mr. May and Ms. Lau are deemed to be executive officers of HEI for purposes of this Item under the definition of Rule 3b-7 of the SEC’s General Rules and Regulations under the Securities Exchange Act of 1934.

There are no family relationships between any executive officer of HEI and any other executive officer or director of HEI or any arrangements or understandings, between any executive officer or director of HEI and any person, pursuant to which the executive officer or director of HEI was selected.

PART II

ITEM 5.

MARKET FOR REGISTRANTS’ COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

HEI:

The information required by this item is incorporated herein by reference to pages 3, 83 (Note 11, “Regulatory restrictions on net assets”) and 88 (Note 15, “Quarterly information (unaudited)”) of HEI’s Consolidated Financial Statements. Certain restrictions on dividends and other distributions of HEI are described in this report under “Item 1. Business—Regulation and other matters—Restrictions on dividends and other distributions.” HEI’s common stock is traded on the New York Stock Exchange and the total number of holders of record of HEI common stock as of February 11, 2004, was 13,884.

In 2003, HEI issued an aggregate of 8,100 shares of unregistered common stock pursuant to the HEI 1990 Nonemployee Director Stock Plan, as amended and restated effective May 1, 2002 (the HEI Nonemployee Director Plan). Under the HEI Nonemployee Director Plan, each HEI nonemployee director receives, in addition to an annual cash retainer, an annual stock grant of 600 shares of HEI common stock (1,000 shares for the first time grant to a new HEI director) and each nonemployee subsidiary director who is not also an HEI nonemployee director receives an annual stock grant of 300 shares of HEI common stock. The HEI Nonemployee Director Plan is currently the only plan for nonemployee directors and provides for annual stock grants (described above) and annual cash retainers for nonemployee directors of HEI and its subsidiaries.

HEI did not register the shares issued under the director stock plan since their issuance did not involve a “sale” as defined under Section 2(3) of the Securities Act of 1933, as amended. Participation by nonemployee directors of HEI and subsidiaries in the director stock plans is mandatory and thus does not involve an investment decision.

Equity compensation plan information

Information as of December 31, 2003 about HEI common stock that may be issued upon the exercise of awards granted under all of the Company’s equity compensation plans was as follows:


Plan category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights ⁽¹⁾	(b) Weighted-average exercise price of outstanding options, warrants and rights		(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) ⁽²⁾
Equity compensation plans approved by shareholders	849,039	$	38.04	2,271,436

⁽¹⁾	This represents the number of shares under options outstanding as of December 31, 2003 and dividend equivalent shares accrued as of December 31, 2003 under such options.

⁽²⁾	This represents the number of shares remaining available as of December 31, 2003, including 2,236,297 under the 1987 Stock Option and Incentive Plan of HEI as amended and restated effective January 21, 2003 and 35,139 under the HEI Nonemployee Director Plan.

HECO:

The information required with respect to “Market information” and “holders” is not applicable to HECO. Since the corporate restructuring on July 1, 1983, all the common stock of HECO has been held solely by its parent, HEI, and is not publicly traded.

The dividends declared and paid on HECO’s common stock for the four quarters of 2003 and 2002 were as follows:


Quarters ended	2003		2002
March 31	$	15,290,000	$	9,233,000
June 30		13,242,000		10,180,000
September 30		13,917,000		11,925,000
December 31		15,270,000		12,805,000

See the discussion of regulatory restrictions on distributions in Note 12 to HECO’s Consolidated Financial Statements.

ITEM 6.

SELECTED FINANCIAL DATA

HEI:

The information required by this item is incorporated herein by reference to page 3 of HEI’s Annual Report.

HECO:

Selected Financial Data

Hawaiian Electric Company, Inc. and Subsidiaries


Years ended December 31	2003			2002			2001			2000			1999
(in thousands)
Income statement data
Operating revenues	$	1,393,038		$	1,252,929		$	1,284,312		$	1,270,635		$	1,050,323
Operating expenses		1,268,200			1,117,772			1,148,980			1,137,474			927,482

Operating income		124,838			135,157			135,332			133,161			122,841
Other income		6,170			7,095			7,436			9,935			8,054

Income before interest and other charges		131,008			142,252			142,768			143,096			130,895
Interest and other charges		51,017			50,967			53,388			54,730			54,495

Income before preferred stock dividends of HECO		79,991			91,285			89,380			88,366			76,400
Preferred stock dividends of HECO		1,080			1,080			1,080			1,080			1,178

Net income for common stock	$	78,911		$	90,205		$	88,300		$	87,286		$	75,222


*At December 31*	2003			2002			2001			2000			1999
(dollars in thousands)
Balance sheet data
Utility plant	$	3,531,299		$	3,381,316		$	3,270,855		$	3,162,779		$	3,034,517
Accumulated depreciation		(1,290,929	)		(1,205,336	)		(1,120,858	)		(1,039,475	)		(960,347	)

Net utility plant	$	2,240,370		$	2,175,980		$	2,149,997		$	2,123,304		$	2,074,170

Total assets	$	2,581,256		$	2,493,436		$	2,423,836		$	2,406,944		$	2,304,076

Capitalization:¹
Short-term borrowings from non-affiliates and affiliate	$	6,000		$	5,600		$	48,297		$	113,162		$	107,013
Long-term debt, net		699,420			705,270			685,269			667,731			646,029
Preferred stock not subject to mandatory redemption		34,293			34,293			34,293			34,293			34,293
HECO-obligated preferred securities of subsidiary trusts		100,000			100,000			100,000			100,000			100,000
Common stock equity		944,443			923,256			877,154			825,012			806,103

Total capitalization	$	1,784,156		$	1,768,419		$	1,745,013		$	1,740,198		$	1,693,438

Capital structure ratios (%)¹
Debt		39.6			40.2			42.0			44.9			44.5
Preferred stock		1.9			1.9			2.0			2.0			2.0
HECO-obligated preferred securities of subsidiary trusts		5.6			5.7			5.7			5.7			5.9
Common stock equity		52.9			52.2			50.3			47.4			47.6

¹	Includes amounts due within one year, short-term borrowings from nonaffiliates and affiliate, and sinking fund and optional redemption payments.

HEI owns all of HECO’s common stock. Therefore, per share data is not meaningful.

See Note 11, “Commitments and Contingencies,” in HECO’s “Notes to Consolidated Financial Statements” for a discussion of certain contingencies that could adversely affect the Company’s future results of operations and financial condition.

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

HEI:

The information required by this item is set forth in HEI’s MD&A, incorporated herein by reference to pages 4 to 35 of HEI’s Annual Report.

HECO:

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read in conjunction with Hawaiian Electric Company, Inc.’s (HECO’s) consolidated financial statements and accompanying notes.

Overview and strategy

HECO and its electric public utility subsidiaries (collectively, the Company) are vertically integrated and regulated by the Hawaii Public Utilities Commission (PUC). Hawaii has not experienced any of the disaggregation or deregulation that has occurred in the industry on the U. S. mainland over the past several years. Keys to achieving reasonable returns are containing costs, retaining customers by providing reliable service and maintaining close customer relationships, and receiving rate increases when needed. The success of the Company’s strategy will be heavily influenced by Hawaii’s general economic conditions and tourism. Real gross state product grew by 2.9% in 2003 and the State of Hawaii Department of Business, Economic Development and Tourism (DBEDT) has projected that gross state product will grow by 2.8% in 2004. However, if a strike in the concrete business on Oahu that began in early February 2004 continues, it may become increasingly difficult for the state economy to achieve such growth in 2004.

Reliability projects remain a priority for HECO and its subsidiaries and significant progress was made in enhancing reliability in 2003. After years of delays, the Keahole power plant expansion on the island of Hawaii resumed construction in November 2003 and the units are now expected to go online in the second quarter of 2004 and be fully operational by December 31, 2004, providing needed generation to the fast-growing communities in West Hawaii. A request to approve a new plan for the East Oahu Transmission Project, an important reliability project for the major transmission grid on the island of Oahu, was filed with the PUC in December 2003. Also on Oahu, a new fuel oil pipeline has been approved by the PUC and is under construction.

Major infrastructure projects can have a pronounced impact on the communities in which they are located. The Company has expanded its community outreach and consultation process so they can better understand and evaluate community concerns early in the process.

With large power users in its service territories, such as the U.S. military, hotels and state and local government, management believes that retaining customers by maintaining customer satisfaction is a critical component in achieving KWH sales and revenue growth in Hawaii over time. The Company has established programs that offer these customers specialized services and energy efficiency audits to help them save on energy costs.

HECO plans to file an application for a rate case in the second half of 2004, based on a 2005 test year. The final decision for the last rate case on Oahu was issued in 1995. HECO and its subsidiaries forecast that cash flows from operations over the next five years will cover their capital expenditures and dividend requirements, except for slight increases in long-term debt from the drawdown of outstanding revenue bond proceeds and in short-term borrowings, which will fluctuate during this period.

Besides installing new generating units, the Company’s long-term plan to meet Hawaii’s future energy needs includes their support of energy conservation and efficiency through demand-side management programs and initiatives to pursue a range of energy choices, including renewable energy and new power supply technologies such as distributed generation. In late 2002, HECO formed a new subsidiary, Renewable Hawaii, Inc. (RHI), which will invest up to $10 million in renewable energy projects to advance the long-term development of renewable energy in Hawaii. Requests for proposals have been issued for projects and RHI is presently evaluating the viability of several projects.

Net income was $79 million in 2003 compared to $90 million in 2002. A swing of $24 million in retirement benefits expense, from a credit of $10 million in 2002 to an expense of $14 million in 2003, was a primary cause of the decline. Pension expense in 2004 is expected to be $6 million lower than in 2003. KWH sales growth was up 2.4% for the year

and growth was particularly strong at 5.1% for the island of Hawaii. Assuming a near-term resolution of the current strike and continuing strength in the U.S. and Hawaii economies, management expects higher KWH sales again in 2004.

From time to time, the Company considers various strategies designed to enhance their competitive positions and to maximize shareholder value. These strategies may include the formation of new subsidiaries or the acquisition or disposition of businesses. The Company may from time to time be engaged in preliminary discussions, either internally or with third parties, regarding potential transactions. Management cannot predict whether any of these strategies or transactions will be carried out or, if so, whether they will be successfully implemented.

Economic conditions

Because it provides local electric utility services, the Company’s operating results are significantly influenced by the strength of Hawaii’s economy, which has been growing modestly. Growth in real gross state product was 2.7% and 2.9% in 2002 and 2003, respectively.

Tourism is widely acknowledged as the largest component of the Hawaii economy. Direct and indirect tourism dollars accounted for approximately 17% of 2002 gross state product, 22% of civilian jobs and 26% of state and local taxes based on a study conducted by DBEDT. In 2000, visitor arrivals reached a high of 7 million. In 2001, arrivals were pacing 2000 levels when the terrorist acts of September 11^th negatively impacted tourism, especially Japanese arrivals. In 2003, the war in Iraq and the outbreak of SARS in Asia provided additional reasons for Japanese tourists not to travel. While tourism has since rebounded, visitor arrivals have lagged the 2000 record arrival levels. Total visitor arrivals in 2003 were 6.3 million, down 0.7% from 2002, due to a combination of a weak international visitor market (down 9.0%) and a strong domestic market (up 3.2%). Positives in 2003 tourism were: visitors stayed longer, evidenced by a 3.0% increase in total visitor days; hotel occupancy levels reached 72.8% through November 2003, 2.7% higher than occupancy rates for the same period of 2002; and visitor expenditures are expected to be $10.5 billion for 2003, which would represent a 4.8% increase over 2002 visitor expenditures. Also in 2003, visitor days, which reflect both visitor arrivals and length of stay, were 62 million, also a record high for Hawaii tourism.

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 showing a growing presence with several key military construction projects slated to begin in 2004, including $3 billion of housing renewal projects, $0.7 billion in construction for an Army Stryker Brigade and over $150 million to prepare for the arrival of eight C-17 cargo planes at Hickam Air Force Base.

In general, the construction industry in Hawaii has been doing well. Private building permits were up 37.8% overall for the year through November 2003 compared with the same period in 2002, and were also up in all categories—residential (up 24.0%), commercial and industrial (up 110.7%) and additions and alterations (up 28.0%). Local economists anticipate year-end data to reflect 7% growth in construction in 2003 and have forecast a 17% increase for 2004. However, in early February 2004, employees of the principal manufacturers of concrete on Oahu went on strike, causing a slowdown in construction in Hawaii—halting many construction projects and leading to hundreds of layoffs in the construction industry. The slowdown in construction activity will temporarily delay electricity demand from new customers. A prolonged strike could significantly adversely affect Hawaii’s construction industry and the Hawaii economy in general.

Hawaii’s improving economy in 2003 is also reflected in other general economic statistics. Total salary and wage jobs increased by 2.2% in 2003 versus 2002. Hawaii’s unemployment rate of 3.8% was well below the national average of 5.4% at the end of 2003. DBEDT also estimates real personal income growth of 3.5% in 2003 compared to 2002.

Given these positive trends in key non-tourism sectors and overall economic indicators, DBEDT expects Hawaii’s economy to grow moderately by 2.8% in 2004, excluding inflation, but achievement of such growth is subject to numerous variables and unknowns. Future growth in Hawaii’s economy is expected to be tied primarily to the rate of expansion in the mainland U.S. and Japan economies and increased military spending, and remains vulnerable to uncertainties in the world’s geopolitical environment.

Results of Operations


(in millions, except per barrel amounts and number of employees)	2003			% change		2002			% change		2001
Revenues ¹	$	1,393		11		$	1,253		(2	)	$	1,284
Expenses
Fuel oil		389		25			311		(10	)		347
Purchased power		368		13			326		(3	)		338
Other		511		6			481		4			464
Operating income		125		(8	)		135		—			135
Allowance for funds used during construction		6		6			6		(11	)		6
Net income		79		(13	)		90		2			88
Return on average common equity		8.5	%				10.0	%				10.4	%
Average price per barrel of fuel oil ¹	$	36.23		25		$	29.10		(13	)	$	33.49
Kilowatthour sales		9,775		2			9,544		2			9,370
Number of employees (at December 31)		1,862		(2	)		1,894		(2	)		1,930

¹	The rate schedules contains energy cost adjustment clauses through which changes in fuel oil prices and certain components of purchased energy costs are passed on to customers.

Pension and other postretirement benefits

For 2003, the retirement benefit plan assets generated a total return of nearly 25% for realized and unrealized net gains of $144 million. In contrast, for 2002, 2001 and 2000, the realized and unrealized net losses on retirement benefit plan assets were $106 million, $91 million and $30 million, respectively. Contributions to the retirement benefit plans totaled $31 million in 2003, compared to contributions of $7 million and $4 million during 2002 and 2001, respectively. Contributions are expected to total $11 million in 2004. As of December 31, 2003 and 2002, the market value of such assets was $758 million and $627 million, respectively.

Based on various assumptions (e.g., discount rate and expected return on plan assets, which are noted below) and assuming no further changes in retirement benefit plan provisions, the Company’s accumulated other comprehensive income (AOCI) balance, net of tax benefits, related to the minimum pension liability at December 31, 2003 and 2002 and retirement benefits expense (income), net of income taxes, for 2004 (estimated) will be, and 2003 and 2002 were, as follows:


Years ended December 31	(Estimated) 2004		2003		2002
($ in millions)

Consolidated HECO
AOCI balance, net of tax benefits, December 31	NA		(0.2	)	(0.1	)
Retirement benefits expense (income), net of income taxes ¹	4.6		8.4		(6.2	)

Assumptions
Discount rate, January ¹	6.25	%	6.75	%	7.25	%
Expected return on plan assets	9.00	%	9.00	%	10.00	%

¹	Does not include impact of the Medicare Prescription Drug, Improvement and Modernization Act of 2003.

NA	Not available.

The 2004 estimated retirement benefits expenses, net of income taxes, are forward-looking statements subject to risks and uncertainties, including the impact of plan changes during the year, if any, and the impact of actual information when received (e.g., actual participant demographics as of January 1, 2004).

•

In 2003, revenues increased by 11%, or $140 million, from 2002 primarily due to higher energy prices ($111 million), a 2.4% increase in KWH sales of electricity ($32 million) and higher demand-side management

(DSM) lost margins and shareholder incentives ($4 million), partly offset by lower DSM program and Integrated Resource Plan (IRP) costs to be recovered ($5 million). The increase in 2003 KWH sales from 2002 was primarily due to increases in the number of residential customers and residential and commercial usage resulting in part from an improving Hawaii economy (higher visitor days and strong real estate market) and warmer weather (more air conditioning usage). The growth in sales was achieved despite the impact on tourism of concerns over the Japanese economy, the war in Iraq, terrorism and SARS. Cooling degree days were 4.4% higher in 2003 compared to 2002.

Operating income was $10 million lower than 2002 mainly due to higher other expenses, primarily higher retirement benefit expenses.

Fuel oil expense and purchased power expense in 2003 increased by 25% and 13%, respectively, due primarily to higher fuel prices, which are generally passed on to customers, and more KWHs generated and purchased.

Other expenses were up 6% in 2003 due to an 18% (or $24 million) increase in “other operation” expense; a 5% (or $5 million) increase in depreciation expense due to additions to plant in service in 2002, including HECO’s Kewalo-Kamoku 138 kilovolt (kV) line; a 9% (or $11 million) increase in taxes, other than income taxes, primarily due to the increase in revenues; partly offset by a 3% (or $2 million) decrease in maintenance expense due in part to less underground distribution line corrective maintenance. As the Companies focused on capital expenditures to ensure reliability, ducted cables were installed to replace, rather than repair, direct buried cables when cable problems occurred.

“Other operation” expense increased 18% primarily due to higher retirement benefits expense and environmental expenses (including higher emission fees). Pension and other postretirement benefit costs, net of amounts capitalized, swung $24 million over 2002 ($14 million expense in 2003 versus a $10 million credit in 2002), partly due to revised assumptions (decreasing the discount rate 50 basis points to 6.75% and the long-term rate of return on assets 100 basis points to 9.0% as of December 31, 2002 compared to December 31, 2001). As of December 31, 2003, the discount rate was further reduced to 6.25%, but retirement benefits expense in 2004 is expected to be $6 million lower than 2003 due to the improved performance of plan assets and contributions made in 2003. “Other operation” expense for 2003 also included $3.1 million of charges related to a settlement reached in December 2003 involving the expansion of the existing plant at Keahole on the island of Hawaii (see Note 11 in HECO’s “Notes to Consolidated Financial Statements”), offset by lower DSM and IRP costs. In January 2004, the Department of Health of the State of Hawaii (DOH) announced that it intended to waive 2003 emissions fees; thus, 2003 emissions fees of $1.5 million, which were accrued in 2003, were reversed in the first quarter of 2004.

•

In 2002, revenues decreased by 2%, or $31 million, from 2001 primarily due to lower energy prices ($60 million), partly offset by a 1.9% increase in KWH sales of electricity ($25 million). The increase in 2002 KWH sales from 2001 was primarily due to increases in residential usage and the number of residential customers and a recovery in the local economy following the events of the September 11, 2001 terrorist attacks, in spite of cooler temperatures which typically result in lower residential and commercial air conditioning usage. Operating income for 2002 was slightly lower than 2001. Fuel oil expense decreased 10% due primarily to lower fuel oil prices, partly offset by more KWHs generated. Purchased power expense decreased 3% due primarily to lower fuel prices and lower purchased capacity payments to an IPP who was able to produce only an average of about 5.6 megawatt (MW) of firm capacity since April 2002 compared to the 30 MW the IPP contracted to provide to HELCO. Other expenses were up 4% due to a 5% increase in “other operation” expense (including $7 million lower retirement benefits income, net of amounts capitalized, primarily due to a 25 basis points lower discount rate and the market performance of plan assets – i.e., $10 million retirement benefits income in 2002 compared to $17 million in 2001), an 8% increase in maintenance expense partly due to the timing and larger scope of generating unit overhauls, a 5% increase in depreciation expense due to additions to plant in service in 2001, partly offset by a 1% decrease in taxes, other than income taxes. Allowance for funds used during construction (AFUDC) for 2002 was 11% lower than 2001 due to the lower base on which AFUDC was calculated. Interest expense decreased 6% from 2001 due to lower short-term borrowings and interest rates.

Recent rate requests

HECO, HELCO and MECO 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. As of February 11, 2004, 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 (decision and order (D&O) issued on December 11, 1995, based on a 1995 test year), 11.50% for Hawaii Electric Light Company, Inc. (HELCO) (D&O issued on February 8, 2001, based on a 2000 test year) and 10.94% for Maui Electric Company, Limited (MECO) (amended D&O issued on April 6, 1999, based on a 1999 test year). For 2003, the actual simple average ROACEs (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 ROACE for 2003 of 6.61%, compared to 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 (currently estimated at approximately $0.6 million after tax per month) is expected to continue to have a negative impact on HELCO’s ROACE for 2004.

As of February 11, 2004, 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 (calculated under the rate-making method) for HECO, HELCO and MECO were 7.95%, 8.65% and 8.79%, respectively.

Hawaiian Electric Company, Inc. HECO has not initiated a rate case in about ten years, 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 “Other regulatory matters, Demand-side management programs – agreements with the Consumer Advocate.”

In October 2002, HECO filed an application with the PUC for approval to change its depreciation rates and to change to vintage amortization accounting for selected plant accounts, which changes would have amounted to an estimated $4.2 million, or 6.3%, increase in HECO’s annual depreciation expense based on a study of depreciation expense for 2000. In its application, HECO requested that the effective date of the proposed changes coincide with the effective date of the rates established in HECO’s next rate case proceeding so that HECO’s financial results would not be negatively impacted by the depreciation rates and method ultimately approved by the PUC. In July 2003, the Consumer Advocate submitted its direct testimony and recommended depreciation expense approximately $31.8 million, or 45%, less than HECO’s requested $70.8 million in annual depreciation expense. In March 2004, HECO and the Consumer Advocate reached an agreement, subject to PUC approval. Under the agreement, HECO would change its depreciation rates and change to vintage amortization accounting for selected plant accounts, effective with the PUC’s final decision and order in this application. If approved by the PUC, the settlement agreement would result in an estimated $65.0 million in annual depreciation expense for 2000.

Hawaii Electric Light Company, Inc. In early 2001, HELCO received a final D&O from the PUC authorizing an $8.4 million, or 4.9% increase in annual revenues, effective February 15, 2001 and based on an 11.50% ROACE. The D&O included in rate base $7.6 million for pre-air permit facilities needed for the delayed Keahole power plant expansion project that the PUC had also found to be used or useful to support the existing generating units at Keahole. The timing of a future HELCO rate increase request to recover costs relating to the delayed Keahole power plant expansion project, i.e., adding two combustion turbines (CT-4 and CT-5) at Keahole, including the remaining cost of pre-air permit facilities, will depend on future circumstances. See “HELCO power situation” in Note 11 in HECO’s “Notes to Consolidated Financial Statements.”

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

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 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. In 2002, MECO’s revenues from shareholder incentives were $0.7 million lower than the amount that would have been recorded if MECO had not agreed to cap such incentives when its authorized ROR was exceeded. Also in 2002, HELCO slightly exceeded its authorized ROR resulting in a reduction of revenues from shareholders incentives for 2002 by $31,000 (recorded in January 2003). In 2002, HECO did not exceed its authorized ROR. In 2003, none of the electric utilities exceeded their respective authorized RORs.

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 will be filed in the second half of 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.

Collective bargaining agreements

HECO, HELCO and MECO reached a new collective bargaining agreement in 2003 with the union which represents approximately 60% of its employees. See “Collective bargaining agreements” in Note 11 in HECO’s “Notes to Consolidated Financial Statements.”

Legislation

Congress and the Hawaii legislature periodically consider legislation that could have positive or negative effects on the utilities and their customers. For example, although it is currently stalled in a House-Senate conference committee, comprehensive energy legislation is still before Congress that could increase the domestic supply of oil as well as increase support for energy conservation programs and mandate the use of renewables by utilities. The 2003 Hawaii legislature considered measures that would undertake a comprehensive audit of Hawaii’s electric utility regulatory policies, energy policies and support for reducing Hawaii’s use of imported petroleum for electrical generation, and a measure to remove the cap on the amount of net energy metering the utilities would be required to make available to eligible customers. These measures were not enacted into law. The legislature did, however, pass a more restricted bill calling for a management audit of the PUC and Consumer Advocate. Also, on June 26, 2003, the Governor signed into law the Hawaii State tax credit for renewable energy, which extends the existing tax credit of 35% of the cost of residential solar water heating (up to $1,750) until at least 2008.

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

The 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. The electric utilities continue to initiate and support many renewable energy research and development projects to help develop these technologies (e.g., photovoltaic projects). They are also conducting integrated resource planning to evaluate the use of more renewables and, in December 2002, HECO formed a nonregulated subsidiary, Renewable Hawaii, Inc. (RHI), to invest in renewable energy projects. In 2003 and 2004, 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 currently reviewing proposals received. 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. Over 8% of consolidated electricity sales for 2003 were from renewable resources (as defined under the renewable portfolio standard law). While the Company thus met the 7% target for 2003 provided for in the 2001 Hawaii legislation, it believes it may be difficult to meet the renewable portfolio standard goals 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.

Effects of inflation

U.S. inflation, as measured by the U.S. Consumer Price Index, averaged 2.3% in 2003, 1.6% in 2002 and 2.8% in 2001. Hawaii inflation, as measured by the Honolulu Consumer Price Index, averaged 2.3% in 2003, 1.2% in 2002 and 1.2% in 2001. Although the rate of inflation over the past several years has been low, inflation continues to have an impact on the Company’s operations.

Inflation increases operating costs and the replacement cost of assets. With significant physical assets, HECO and its subsidiaries replace assets at much higher costs and must request and obtain rate increases to maintain adequate earnings. In the past, the PUC has generally approved rate increases to cover the effects of inflation. The PUC granted rate increases in 2001 and 2000 for HELCO, and in 1999 for MECO, in part to cover increases in construction costs and operating expenses due to inflation.

Recent accounting pronouncements

See “Recent accounting pronouncements and interpretations” in Note 1 in HECO’s “Notes to Consolidated Financial Statements.”

Liquidity and capital resources

The Company believes that its ability to generate cash, both internally from 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 Company’s total assets were $2.6 billion at December 31, 2003 and $2.5 billion at December 31, 2002.

HECO’s consolidated capital structure was as follows:


December 31	2003				2002
(in millions)
Short-term borrowings	$	6	—	%	$	6	—	%
Long-term debt, net		699	39			705	40
HECO-obligated preferred securities of trust subsidiaries		100	6			100	6
Preferred stock		34	2			34	2
Common stock equity		945	53			923	52

	$	1,784	100	%	$	1,768	100	%

As of February 11, 2004, the Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HECO securities were as follows:


	S&P	Moody’s
Commercial paper	A-2	P-2
Revenue bonds (senior unsecured, insured)	AAA	Aaa
HECO-obligated preferred securities of trust subsidiaries	BBB-	Baa2
Cumulative preferred stock (selected series)	NR	Baa3

NR	Not rated.

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

In May 2002, S&P revised its credit outlook on HECO securities to stable from negative, citing “recovery in Hawaii’s economy, moderate construction spending, aggressive cost containment, limited competitive pressures, steady banking operations, and expectations for continued financial improvement.”

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

From time to time, HECO 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 December 31, 2003, HECO had $6 million and $26 million of short-term borrowings from HEI and MECO, respectively, and HELCO had $11 million of short-term borrowings from HECO. HECO had an average outstanding balance of commercial paper for 2003 of $0.4 million and had no commercial paper outstanding at December 31, 2003. Management believes that if HECO’s commercial paper ratings were to be downgraded, they might not be able to sell commercial paper under current market conditions.

At December 31, 2003, HECO maintained bank lines of credit totaling $90 million (all maturing in 2004). These lines of credit are principally maintained by 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. There are

no provisions for revised pricing in the event of a ratings change in the lines of credit available to HECO. Further, none of 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 December 31, 2003, the lines were unused. To the extent deemed necessary, HECO anticipates arranging similar lines of credit as existing lines of credit mature. See S&P and Moody’s ratings above and Note 5 in HECO’s “Notes to Consolidated Financial Statements.”

In 2003, the Company’s investing activities used $134 million in cash, primarily for capital expenditures. Capital expenditures requiring the use of cash totaled approximately $147.0 million in 2003, of which $91.3 million was attributable to HECO, $29.4 million to HELCO and $26.3 million to MECO. Approximately 58% of the total 2003 capital expenditures was for transmission and distribution projects and approximately 42% was for generation and general plant projects. Cash contributions in aid of construction received in 2003 totaled $13.0 million. Financing activities used net cash of $74 million, including $66 million for the payment of common and preferred stock dividends and preferred securities distributions and $6 million for the net repayment of long-term debt. Operating activities provided cash of $206 million.

In September 2002, the Department of Budget and Finance of the State of Hawaii issued, at a small discount, Series 2002A Special Purpose Revenue Bonds (SPRB) in the principal amount of $40 million with a maturity of 30 years and a fixed coupon interest rate of 5.10% (yield of 5.15%), and loaned the proceeds from the sale to HECO. Payments on these revenue bonds are insured by a financial guaranty insurance policy issued by Ambac Assurance Corporation. As of December 31, 2003, $14 million of proceeds from the Series 2002A sale by the Department of Budget and Finance of the State of Hawaii of special purpose revenue bonds 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). Payments on the revenue bonds issued in May 2003 are insured by a financial guaranty insurance policy issued by XL Capital Assurance Inc.

As further explained in Note 10 in HECO’s “Notes to Consolidated Financial Statements,” the Company maintains pension and other postretirement benefit plans. Funding for the pension plans is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under the Employee Retirement Income Security Act of 1974, as amended (ERISA). The Company was not required to make any contributions to the pension plans to meet minimum funding requirements pursuant to ERISA for 2003, but the Company’s Pension Investment Committee chose to make tax deductible contributions in 2003. Contributions to the pension and postretirement benefit plans totaled $31 million in 2003. Contributions are expected to total $11 million in 2004. The Company’s policy is to comply with directives from the PUC to fund the costs of the postretirement benefit plan. These costs are ultimately collected in rates billed to customers. The Company reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed. Depending on the performance of the assets held in the plans’ trusts and numerous other factors, additional contributions may be required in the future to meet the minimum funding requirements of ERISA or to pay benefits to plan participants. The Company believes it will have adequate access to capital resources to support any necessary funding requirements.

Net capital expenditures for 2004 through 2008 are estimated to total $0.8 billion. 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 slight increase in short-term

borrowings and in long-term debt from the drawdown of outstanding 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.

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 $0.8 billion. 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, with the remaining 48% primarily for generation projects and general plant.

For 2004, 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 Series 2002A sale of 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 combined heat and power (CHP) installations, the effects of opposition to proposed construction projects and requirements of environmental and other regulatory and permitting authorities.

Existing debt or trust preferred securities may be refinanced (potentially at more favorable rates) with additional debt or equity financing (or both). The PUC must approve issuances, if any, of equity and long-term debt securities by HECO, HECO and MECO. In February 2004, the PUC approved the issuance of trust preferred securities by HECO Capital Trust III to refinance the trust preferred securities issued by HECO Capital Trust I in 1997 and/or the trust preferred securities issued by HECO Capital Trust II in 1998. Depending on interest rates and other conditions in the capital markets, the Company’s current plans are to redeem the trust preferred securities of HECO Capital Trust I with the proceeds of the sale of the trust preferred securities of HECO Capital Trust III and to utilize short-term borrowings from HEI and internal funds to effect the redemption of the trust preferred securities issued by HECO Capital Trust II. It is anticipated that HECO will pay down these short-term borrowings over time with lower dividends to HEI. If these refinancings proceed, management expects to complete these redemptions in the second quarter of 2004.

See Note 11 in HECO’s “Notes to Consolidated Financial Statements” for a discussion of fuel and power purchase commitments.

Selected contractual obligations

The following table presents aggregated information about total principal, lease and fuel oil payments and minimum fixed capacity purchase power charges due during the indicated periods under the specified contractual obligations:


December 31, 2003	Payment due by period
(in millions)	Less than 1 year		1-3 years		4-5 years		After 5 years		Total
Contractual obligations
Long-term debt, net	$	—	$	—	$	—	$	699	$	699
HECO-obligated preferred securities of trust subsidiaries		—		—		—		100		100
Operating leases		2		2		1		2		7
Fuel oil purchase obligations (estimate based on January 1, 2004 fuel oil prices)		350		—		—		—		350
Purchase power obligations– minimum fixed capacity charges		123		236		234		1,491		2,084

	$	475	$	238	$	235	$	2,292	$	3,240

The table above does not include other categories of obligations and commitments, such as interest payable, trade payables, obligations under purchase orders and amounts that may become payable in future periods under collective bargaining and other employment agreements and employee benefit plans. As of December 31, 2003, the fair value of the assets held in trusts to satisfy the obligations of the pension and other postretirement benefit plans exceeded the pension plans’ accumulated benefit obligation and the accumulated postretirement benefit obligation for retirees. Thus, no minimum funding requirements for retirement benefit plans have been included in the tables above.

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. The following is a discussion of certain of these factors.

Economic conditions. Because its core business is providing local electric utility services, the Company’s operating results are significantly influenced by the strength of Hawaii’s economy, which in turn is influenced by economic conditions in the mainland U.S. (particularly California) and Asia (particularly Japan) as a result of the impact of those conditions on tourism. See “Results of operations – Economic conditions.”

Competition. The electric utility industry is competitive and the Company’s success in meeting competition will continue to have a direct impact on the Company’s financial performance. The generation sector of the electric utility industry has become increasingly competitive in Hawaii. Although competition in the generation sector in Hawaii has been moderated by the scarcity of generation sites, various permitting processes and lack of interconnections to other electric utilities, several independent power producers (IPPs) have established power purchase agreements with the Company, and customer self-generation, with or without cogeneration, is a continuing competitive factor.

Recent developments involving distributed generation. Historically, HECO, HELCO and MECO 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 CHP systems, is growing. CHP systems are a form of distributed generation (DG), and produce electricity and thermal energy from gas, propane or diesel-fired engines. In Hawaii, the thermal energy generally is used to heat water and, through an absorption chiller, drive an air conditioning system. The electric energy generated by these systems is usually lower in output than the customer’s

load, which results in continued connection to the utility grid to make up the difference in electricity demand and to provide back up electricity.

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

In July 2003, three vendors of DG/CHP equipment and services proposed, in an informal complaint to the PUC, that the PUC open a proceeding to investigate the Company’s 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 Company will be permitted to engage in utility-owned DG at individual customers sites. In August 2003, the Company responded to the informal complaint, and to information requests from the PUC on the CHP demonstration project and 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 PUC also plans to address issues raised in the informal complaint filed by the three vendors of DG/CHP equipment. In March 2004, the PUC issued an order which granted motions by several parties to intervene or participate without intervention in the DG docket. In its order, the PUC also ordered the parties and participants to meet to formulate for PUC approval by April 2, 2004, the issues, procedures, schedule and the degree of participation by the participants.

In October 2003, the Company filed an application for approval of a CHP tariff, under which it would provide CHP services to eligible commercial customers. Under the tariff, the Company 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 completion of the DG docket and approval of a tariff in the CHP application, the Company plans to request approval for individual CHP projects.

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

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

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

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

policies to encourage wholesale competition and the continuing examination of other areas suitable for the development of competition.”

In October 2003, the PUC closed the competition proceeding instituted in 1996. The PUC found that developments in other states indicate that, at best, implementation of retail access would be premature, and determined that no action will be taken to implement retail electric competition in Hawaii at this time. The PUC concluded that projections of any potential benefits of restructuring Hawaii’s electric industry are too speculative and that it has not been sufficiently demonstrated that all consumers in Hawaii would continue to receive adequate, safe, reliable, and efficient energy services at fair and reasonable prices under a restructured market at this time. The PUC indicated it will take a cautious approach to restructuring and will continue to monitor restructuring experiences in other states and at the federal level before proceeding with any major restructuring in Hawaii. The PUC determined that it was in the public interest to work within the current regulatory system to strive to improve efficiency within the electric industry, and opened investigative dockets on competitive bidding and DG to move toward a more competitive electric industry environment under cost-based regulation. The stated purpose of the 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 the docket. The PUC has made the electric utilities in Hawaii and the Consumer Advocate parties to the new proceedings. Motions to intervene or participate were filed by parties in the competitive bidding investigative docket. Management cannot predict the ultimate outcome of these proceedings.

U.S. capital markets and interest rate environment. Changes in the U.S. capital markets can have significant effects on the Company. For example, the Company estimates that consolidated retirement benefits expense, net of amounts capitalized and income taxes, will be $5 million in 2004 as compared to $8 million in 2003, and that the Company’s contributions to the retirement benefit plans will be $11 million in 2004 as compared to $31 million in 2003, partly as a result of the performance of HEI’s retirement benefit plans’ assets. See “Quantitative and Qualitative Disclosures about Market Risk.”

Technological developments. New technological developments (e.g., the commercial development of fuel cells or distributed generation) may impact the Company’s future competitive position, results of operations and financial condition.

Limited insurance. In the ordinary course of business, the Company purchases insurance coverages (e.g., property and liability coverages) to protect itself against loss of or damage to its properties and against claims made by third-parties and employees for property damage or personal injuries. However, the protection provided by such insurance is limited in significant respects and, in some instances, the Company has no coverage. For example, the Company’s overhead and underground transmission and distribution systems (with the exception of substation buildings and contents) have a replacement value roughly estimated at $2 billion and are uninsured because the amount of transmission and distribution system insurance available is limited and the premiums are cost prohibitive. Similarly, the Company has no business interruption insurance as the premiums for such insurance would be cost prohibitive, particularly since the utilities are not interconnected to other systems. If a hurricane or other uninsured catastrophic natural disaster should occur, and the PUC does not allow the Company to recover from ratepayers restoration costs and revenues lost from business interruption, the Company’s results of operations and financial condition could be materially adversely impacted. Also, certain of the Company’s insurance has substantial “deductibles” or has limits on the maximum amounts that may be recovered. Insurers have also introduced new exclusions or limitations of coverage for claims related to certain perils including, but not limited to, mold and terrorism. If a series of losses occurred, such as from a series of lawsuits in the ordinary course of business each of which were subject to the deductible amount, or if the maximum limit of the available insurance were substantially exceeded, the Company could incur losses in amounts that would have a material adverse effect on its results of operations and financial condition.

Environmental matters. HECO and its subsidiaries are subject to environmental laws and regulations that regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic substances. These laws and regulations, among other things, require that certain environmental permits be obtained as a condition to constructing or operating certain facilities, and obtaining such permits can entail significant expense and cause substantial construction delays. Also, these laws and regulations

may be amended from time to time, including amendments that increase the burden and expense of compliance. Management believes that the recovery through rates of most, if not all, of any costs incurred by HECO and its subsidiaries in complying with environmental requirements would be allowed by the PUC.

The entire electric utility industry is affected by the 1990 Amendments to the Clean Air Act, recent changes to the National Ambient Air Quality Standard (NAAQS) for ozone, and adoption of a NAAQS for fine particulate matter. Possible changes to the federal New Source Review permitting regulations, as well as new regulatory programs, if enacted, regarding global warming and mandating further reductions of certain air emissions will also pose challenges for the industry. If the Clear Skies Bill is adopted as currently proposed, HECO, and to a lesser extent, its subsidiaries, will likely incur significant capital and operations and maintenance costs beginning one to two years after enactment.

HECO, HELCO and MECO, like other utilities, periodically identify leaking petroleum-containing equipment such as underground storage tanks, piping and transformers. The electric utilities report releases from such equipment when and as required by applicable law and address impacts due to the releases in compliance with applicable regulatory requirements.

The Honolulu Harbor environmental investigation, described in Note 11 in HECO’s “Notes to Consolidated Financial Statements,” is an ongoing environmental investigation. Although this investigation is expected to entail significant expense over the next several years, management does not believe, based on information available to the Company at this time, that the costs of this investigation or any other contingent liabilities relating to environmental matters will have a material adverse effect on the Company. However, there can be no assurance that a significant environmental liability will not be incurred by the Company, including with respect to the Honolulu Harbor environmental investigation.

Regulation of electric utility rates. The PUC has broad discretion in its regulation of the rates charged by HECO, HELCO and MECO and in other matters. Any adverse D&O by the PUC concerning the level or method of determining electric utility rates, the authorized returns on equity or other matters, or any prolonged delay in rendering a D&O in a rate or other proceeding, could have a material adverse effect on the Company’s results of operations and financial condition. Upon a showing of probable entitlement, the PUC is required to issue an interim D&O in a rate case within 10 months from the date of filing a completed application if the evidentiary hearing is completed (subject to extension for 30 days if the evidentiary hearing is not completed). There is no time limit for rendering a final D&O. Interim rate increases are subject to refund with interest, pending the final outcome of the case. At December 31, 2003, HECO and its subsidiaries had recognized $17 million of revenues with respect to interim orders regarding certain integrated resource planning costs, which revenues are subject to refund, with interest, to the extent they exceed the amounts allowed in final orders.

Management cannot predict with certainty when D&Os in future rate cases will be rendered or the amount of any interim or final rate increase that may be granted. There are no rate cases pending at this time. HECO, however, has committed to file a rate increase application in the second half of 2004, using a 2005 test year.

The rate schedules of HECO, HELCO and MECO 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 Company believes that the energy cost adjustment clauses continue to be necessary. These clauses were continued in the most recent HELCO and MECO rate cases (final D&O’s issued in February 2001 and April 1999, respectively).

Consultants periodically conduct depreciation studies for the Company to determine whether the existing approved rates and methods used to calculate depreciation accruals are appropriate for the production, transmission, distribution and general plant accounts. If it is determined that the existing rates and methods are no longer appropriate, changes to those rates are recommended as part of the study. In October 2002, HECO filed an application with the PUC for approval to change its depreciation rates and to change to vintage amortization accounting for selected plant accounts, which changes would have amounted to an approximate $4.2 million, or 6.3%, increase in depreciation expense based on a study of depreciation expense for 2000. In its application, HECO requested that the effective date of the proposed changes coincide with the effective date of the rates established in HECO’s next rate case proceeding so that HECO’s financial results would not be impacted by the depreciation rates

and method ultimately approved by the PUC. In March 2004, HECO and the Consumer Advocate reached a settlement agreement in this application, subject to PUC approval. See previous section called “Recent rate requests.”

Fuel oil and purchased power. HECO, HELCO and MECO rely on fuel oil suppliers and independent power producers to deliver fuel oil and power, respectively. The Company estimates that 78% of the net energy generated and purchased in 2004 will be generated from the burning of oil. Purchased KWHs provided approximately 39.2% of the total net energy generated and purchased in 2003 compared to 38.0% in 2002 and 39.0% in 2001.

Failure by the Company’s oil suppliers to provide fuel pursuant to existing supply contracts, or failure by a major independent power producer to deliver the firm capacity anticipated in its power purchase agreement, could interrupt the ability of the Company to deliver electricity, thereby materially adversely affecting the Company’s results of operations and financial condition. HECO, however, maintains an inventory of fuel oil in excess of one month’s supply, and HELCO and MECO maintain approximately a one month’s supply of both medium sulfur fuel oil and diesel fuel. The Company’s major sources of oil, through their suppliers, are in Alaska, Indonesia and the Far East. Some, but not all, of the Company’s power purchase agreements require that the independent power producers maintain minimum fuel inventory levels and all of the firm capacity power purchase agreements include provisions imposing substantial penalties for failure to produce the firm capacity anticipated by those agreements.

Other regulatory and permitting contingencies. Many public utility projects require PUC approval and various permits (e.g., environmental and land use permits) from other agencies. Delays in obtaining PUC approval or permits can result in increased costs. If a project does not proceed or if the PUC disallows costs of the project, the project costs may need to be written off in amounts that could have a material adverse effect on the Company. Two major capital improvement utility projects, the Keahole project and the East Oahu Transmission Project, have encountered opposition and the Keahole project has been seriously delayed (although this project is now scheduled for completion during 2004). See Note 11 in HECO’s “Notes to Consolidated Financial Statements.”

Material estimates and critical accounting policies

In preparing the consolidated financial statements and related disclosures in conformity with accounting principles generally accepted in the United States of America, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the period reported. Management reviews these estimates and assumptions periodically and reflects the effect of revisions in the period that they are determined to be necessary. 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 utility plant; pension and other postretirement benefit obligations; contingencies and litigation; income taxes; regulatory assets and liabilities; and revenues.

In accordance with SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” management has identified the following accounting policies to be the most critical to the Company’s financial statements—that is, management believes that these policies are both the most important to the portrayal of the Company’s results of operations and financial condition, and currently require management’s most difficult, subjective or complex judgments. Management has reviewed the material estimates and critical accounting policies with the HECO Audit Committee.

For additional discussion of the Company’s accounting policies, see Note 1 in HECO’s “Notes to Consolidated Financial Statements.”

Utility plant. Utility plant is reported at cost. Self-constructed utility plant includes engineering, supervision, and administrative and general costs, and an allowance for the cost of funds used during the construction period. These costs are recorded in construction in progress and are transferred to utility plant when construction is completed and the facilities are either placed in service or become useful for public utility purposes. Upon the retirement of utility plant, no gain or loss is recognized. The cost of the utility plant retired is charged to accumulated depreciation. Amounts collected from customers for cost of removal (expected to exceed salvage value in the future) are included in regulatory liabilities.

Management believes that the PUC will allow recovery of utility plant in its electric rates. If the PUC does not allow recovery of any such costs, the Company would be required to write off the disallowed costs at that time. See the

discussion in Note 11 in HECO’s “Notes to Consolidated Financial Statements” concerning costs recorded in construction in progress for CT-4 and CT-5 at Keahole and the proposed East Oahu Transmission Project.

Pension and other postretirement benefits obligations. Pension and other postretirement benefit (collectively, retirement benefits) costs/(returns) are charged/(credited) primarily to expense and utility plant.

The Company’s reported costs of providing retirement benefits (described in Note 10 in HECO’s “Notes to Consolidated Financial Statements”) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. For example, pension and other postretirement benefit costs are impacted by actual employee demographics (including age and compensation levels), the level of contributions to the plans and earnings on plan assets. Changes made to the provisions of the plans may also impact current and future costs. (No changes were made to the retirement benefit plans’ provisions in 2003, 2002 and 2001 that have had a significant impact on recorded retirement benefit plan amounts.) Costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used.

As a result of the factors listed above, significant portions of pension and other postretirement benefit costs recorded in any period do not reflect the actual benefits provided to plan participants. For 2003 and 2002, the Company recorded other postretirement benefit expense, net of amounts capitalized, of approximately $7 million and $4 million, respectively, in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” Actual payments of such benefits made to retirees during 2003 and 2002 were $7 million and $6 million, respectively. In accordance with SFAS No. 87, “Employers’ Accounting for Pensions,” changes in pension obligations associated with the factors noted above may not be immediately recognized as pension costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. For 2003 and 2002, the Company recorded non-cash pension expense (income), net of amounts capitalized, of approximately $7 million and $(14) million, respectively, and paid pension benefits of $36 million and $34 million, respectively.

The assumptions used by management in making benefit and funding calculations are based on current economic conditions. Changes in economic conditions will impact the underlying assumptions in determining retirement benefit costs on a prospective basis. In selecting an assumed discount rate, the Company benchmarks its discount rate assumption to the Moody’s 20-year AA Corporate Bond Composite Index. In selecting an assumed rate of return on plan assets, the Company considers economic forecasts for the types of investments held by the plan and the past performance of plan assets.

As presented in Note 10 in HECO’s “Notes to Consolidated Financial Statements,” the Company has revised its discount rate as of December 31, 2003 compared to December 31, 2002. The change did not have an impact on reported costs in 2003; however, for future years, this change will have a significant impact. Based upon the revised discount rate (decreased 50 basis points to 6.25%) and plan assets as of December 31, 2003, the Company estimates that retirement benefits expense, net of amounts capitalized and income taxes, will be $5 million in 2004 as compared to $8 million in 2003. In determining the retirement benefit costs, assumptions can change from period to period, and such changes could result in material changes to these estimated amounts.

The Company’s plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased retirement benefit costs and contributions in future periods.

The following tables reflect the sensitivities of the projected benefit obligation (PBO) and accumulated postretirement benefit obligation (APBO) as of December 31, 2003, and 2004 net income associated with a change in certain actuarial assumptions by the indicated basis points and constitute “forward-looking statements.” Each sensitivity below reflects an evaluation of the change based solely on a change in that assumption as well as a related change in the contributions to the applicable retirement benefits plan.


Actuarial assumption	Change in assumption in basis points		Impact on PBO/APBO			Impact on 2004 net income
($ in millions)
Pension benefits
Discount rate	50		$	(51.9	)	$	1.2
	(50	)		63.7			(3.4	)
Rate of return on plan assets	50			NA			1.8
	(50	)		NA			(1.8	)
Other benefits¹
Discount rate	50			(9.9	)		0.1
	(50	)		10.9			(0.4	)
Health care cost trend rate	100			3.5			(0.2	)
	(100	)		(4.3	)		0.1
Rate of return on plan assets	50			NA			0.2
	(50	)		NA			(0.2	)

¹	Does not include impact of the Medicare Prescription Drug, Improvement and Modernization Act of 2003.

NA	Not applicable.

Contingencies and litigation. The Company is subject to proceedings, lawsuits and other claims, including proceedings under laws and government regulations related to environmental matters. Management assesses the likelihood of any adverse judgments in or outcomes to these matters as well as potential ranges of probable losses. A determination of the amount of reserves required, if any, for these contingencies is based on a careful analysis of each individual issue often with the assistance of outside counsel. The required reserves may change in the future due to new developments in each matter or changes in approach in dealing with these matters, such as a change in settlement strategy.

In general, environmental contamination treatment costs are charged to expense, unless it is probable that the PUC would allow such costs to be recovered in future rates, in which case such costs would be capitalized as regulatory assets. Also, environmental costs are capitalized if the costs extend the life, increase the capacity, or improve the safety or efficiency of property; the costs mitigate or prevent future environmental contamination; or the costs are incurred in preparing the property for sale. See “Environmental regulation” in Note 11 in HECO’s “Notes to Consolidated Financial Statements” for a description of the Honolulu Harbor investigation.

Income taxes. Deferred income tax assets and liabilities are established for the temporary differences between the financial reporting bases and the tax bases of the Company’s assets and liabilities at enacted tax rates expected to be in effect when such deferred tax assets or liabilities are realized or settled. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.

Management periodically evaluates its potential exposures from tax positions taken that have or could be challenged by taxing authorities. These potential exposures result because taxing authorities may take positions that differ from those taken by management in the interpretation and application of statutes, regulations and rules. Management considers the possibility of alternative outcomes based upon past experience, previous actions by taxing authorities (e.g., actions taken in other jurisdictions) and advice from tax experts. Management believes that the Company’s provision for tax contingencies is reasonable. However, the ultimate resolution of tax treatments disputed by governmental authorities may adversely affect the Company’s current and deferred income tax amounts.

Regulatory assets and liabilities. HECO, HELCO and MECO are regulated by the PUC. In accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” the Company’s financial statements reflect assets, liabilities, revenues and costs based on current cost-based rate-making regulations. The actions of regulators can affect the timing of recognition of revenues, expenses, assets and liabilities.

Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities represent amounts collected from customers for costs that are expected to be

incurred in the future. Historically, the Company, like most electric utilities, had included net salvage (i.e., the cost of removal in excess of salvage value) in accumulated depreciation. Recently, however, the Securities and Exchange Commission provided guidance indicating that net salvage meets the SFAS No. 71 definition of a regulatory liability. Accordingly, the Company reclassified its accumulated net salvage as of December 31, 2003 (and all prior periods presented) from accumulated depreciation to regulatory liabilities. As of December 31, 2003, regulatory liabilities, net of regulatory assets, amounted to $72 million. Regulatory assets and regulatory liabilities are itemized in Note 6 in HECO’s “Notes to Consolidated Financial Statements.” Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment. Because current rates include the recovery of regulatory assets existing as of the last rate case and rates in effect allow the utilities to earn a reasonable rate of return, management believes the regulatory assets as of December 31, 2003 are probable of recovery. This determination assumes continuation of the current political and regulatory climate in Hawaii, and is subject to change in the future.

Management believes its operations currently satisfy the SFAS No. 71 criteria. If events or circumstances should change so that those criteria are no longer satisfied, the Company expects that the regulatory liabilities, net of regulatory assets, would be credited to income. In the event of unforeseen regulatory actions or other circumstances, however, management believes that a material adverse effect on the Company’s results of operations and financial position may result if regulatory assets have to be charged to expense without an offsetting credit from regulatory liabilities.

Revenues. Revenues are based on rates authorized by the PUC and include revenues applicable to energy consumed in the accounting period but not yet billed to the customers. At December 31, 2003, revenues applicable to energy consumed, but not yet billed to the customers, amounted to $60 million.

Revenue amounts recorded pursuant to a PUC interim order are subject to refund, with interest, pending a final order. At December 31, 2003, HECO and its subsidiaries had recognized $17 million of revenues with respect to interim orders regarding certain integrated resource planning costs incurred since 1995, which revenues are subject to refund, with interest, to the extent they exceed the amounts allowed in final orders. If a refund were required, the revenues to be refunded would be immediately reversed on the income statement. The Consumer Advocate has objected to the recovery of $2.5 million (before interest) of the $10.3 million of integrated resource planning costs incurred from 1995 through 2002, and the PUC’s decision is pending on this matter.

The rate schedules of HECO, HELCO and MECO include energy cost adjustment clauses under which electric rates are 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. If the energy cost adjustment clauses were discontinued, the Company’s results of operations could fluctuate significantly as a result of increases and decreases in fuel oil and purchased energy prices. 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 Company believes that the energy cost adjustment clauses continue to be necessary and these clauses were continued in the 2001 and 1999 final D&Os in HELCO’s and MECO’s most recent rate cases.

Consolidation of variable interest entities (VIEs). In December 2003, the Financial Accounting Standards Board (FASB) issued revised FASB Interpretation No. 46 (FIN No. 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. The Company currently anticipates that application of FIN No. 46R will result in a deconsolidation of its subsidary trusts. The Company is evaluating the impact of applying FIN No. 46R in the first quarter of 2004 to its relationships with IPPs from whom it purchases power and has not yet completed this analysis. A possible outcome of the analysis, however, is that HECO (or its subsidiaries, as applicable) may be found to meet the definition of a primary beneficiary of the IPPs, which finding may result in the consolidation of the IPPs in the Company’s consolidated financial statements. The consolidation of IPPs would have a material effect on the Company’s consolidated financial statements, including the recognition of a significant amount of assets and liabilities.

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

HEI:

The information required by this item is incorporated herein by reference to pages 35 to 38 of HEI’s Annual Report.

HECO:

HECO and its subsidiaries’ general policy is to manage interest rate risk through use of a combination of short-term debt, long-term debt (primarily fixed-rate debt) and preferred securities. As of December 31, 2003, management believes HECO and its subsidiaries are exposed to interest rate risk because of the periodic borrowing requirements, impact of the interest rates on the discount rate used to determine retirement benefits expenses and obligations (see sections “Pension and other postretirement benefits” and “Pension and other postretirement benefit obligations” in “Management’s discussion and analysis of financial condition and results of operations” and Note 10 in HECO’s “Notes to consolidated financial statements”) and the possible effect of interest rates on the electric utilities’ allowed rates of return (see “Regulation of electric utility rates” in HECO’s MD&A). Other than these exposures, management believes its exposure to interest rate risk is not material.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

HEI:

The information required by this item is incorporated herein by reference to pages 39 to 88 of HEI’s Annual Report.

HECO:

The information required by this item is incorporated herein by reference to pages 1 to 39 of HECO’s Consolidated Financial Statements.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

HEI and HECO:

None

ITEM 9A.

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 December 31, 2003. Based on their evaluations, as of December 31, 2003, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934) of the Company are effective.

HECO:

T. Michael May, HECO Chief Executive Officer, and Richard A. von Gnechten, HECO Chief Financial Officer, have evaluated the disclosure controls and procedures of HECO as of December 31, 2003. Based on their evaluations, as of December 31, 2003, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934) of HECO are effective.

PART III

ITEM 10.

DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS

HEI:

Information for this item concerning the executive officers of HEI is set forth on pages 46 and 47 of this report. Information on the current HEI directors and their business experience and directorships is incorporated herein by reference to the information under the captions “Nominees for a Class III Director and Class II Directors,” “Continuing Class III Directors” and “Continuing Class I Directors,” in HEI’s 2004 Proxy Statement. The information on the HEI Audit Committee and the Board of Directors determination of HEI’s Audit Committee financial experts and their names are incorporated by reference to the information under the captions “Committees of the Board – What Committees has the Board established and how often did they meet?,” “Committees of the Board – What are the primary functions of each of the four committees?” and “Audit Committee Report” in the 2004 Proxy Statement.

Family relationships; director arrangements

There are no family relationships between any executive officer or director of HEI and any other executive officer or director of HEI or any arrangement or understanding between any executive officer or director of HEI and any person, pursuant to which the executive officer or director of HEI was selected.

Code of Conduct

Information on HEI’s Code of Conduct is incorporated by reference to the information under the caption “Committees of the Board – What is the Company’s philosophy on corporate governance?” in the 2004 Proxy Statement. In connection with its periodic review of corporate governance trends and best practices, the HEI Board of Directors adopted a Revised Code of Conduct, including the code of ethics for, among others, the chief executive officer and senior financial officers of HEI, which may be viewed on HEI’s website at www.hei.com. HEI also elects to disclose the information required by Form 8-K, Item 10, “Amendments to the registrant’s code of ethics, or waiver of a provision of the code of ethics,” through this website and such information will remain available on this website for at least a 12-month period. A copy of the Revised Code of Conduct may be obtained free of charge upon written request from the HEI Vice President-Administration & Corporate Secretary, P.O. Box 730, Honolulu, Hawaii 96808-0730.

Section 16(a) beneficial ownership reporting compliance

For information required to be reported under this caption, see the information under the caption “Stock Ownership Information – Were Section 16(a) beneficial ownership reporting forms filed with the SEC?” in HEI’s 2004 Proxy Statement.

HECO:

Executive Officers

The following persons are, or may be deemed to be, executive officers of HECO. Their ages are given as of February 11, 2004 and their years of company service are given as of December 31, 2003. Officers are appointed to serve until the meeting of the HECO Board of Directors after the next HECO Annual Meeting (which will occur in April 2004) and/or until their respective successors have been appointed and qualified (or until their earlier resignation or removal). Company service includes service with HECO affiliates.


HECO Executive Officers		Business experience for past five years
Robert F. Clarke, age 61
Chairman of the Board		1/91 to date
(Company service: 16 years)
T. Michael May, age 57
President, Chief Executive Officer and Director		9/95 to date
Chairman of the Board, MECO and HELCO		9/95 to date
(Company service: 11 years)


HECO Executive Officers		Business experience for past five years
(continued)

Robert A. Alm, age 52
Senior Vice President – Public Affairs		7/01 to date
(Company service: 2 years)
Robert A. Alm, prior to joining HECO, served as Executive Vice President of Financial Management Group at First Hawaiian Bank from 1/99 to 6/01.

Thomas L. Joaquin, age 60
Senior Vice President – Operations		7/01 to date
Vice President – Power Supply		7/95 to 06/01
(Company service: 30 years)

Karl E. Stahlkopf, age 63
Senior Vice President – Energy Solutions and Chief Technology Officer		5/02 to date
(Company service: 1 year)
Karl E. Stahlkopf, prior to joining HECO, served as Vice President – Power Delivery and Utilization of the Electric Power Research Institute from 1/01 to 5/02; President and CEO of EPRI Solutions from 01/99 to 01/01; and Vice President – Energy Delivery and Utilization of the Electric Power Research Institute from 1/97 to 1/99.

William A. Bonnet, age 60
Vice President – Government & Community Affairs		5/01 to date
President, Maui Electric Company, Inc		9/96 to 5/01
(Company service: 18 years)

Jackie Mahi Erickson, age 63
Vice President & General Counsel		3/03 to date
Vice President – Customer Operations & General Counsel		10/98 to 3/03
(Company service: 22 years)

Charles M. Freedman, age 57
Vice President – Corporate Relations		3/98 to date
(Company service: 12 years)

Chris M. Shirai, age 56
Vice President – Energy Delivery		12/99 to date
Manager, Engineering Department		7/96 to 11/99
(Company service: 34 years)

Thomas C. Simmons, age 55
Vice President – Power Supply		2/02 to date
Manager, Power Supply		7/95 to 2/02
(Company service: 32 years)


HECO Executive Officers		Business experience for past five years
(continued)

Richard A. von Gnechten, age 40
Financial Vice President		12/00 to date
Assistant Treasurer and Manager, Financial Services		5/00 to 11/00
Manager, Customer Service		12/96 to 5/00
(Company service: 12 years)

Patricia U. Wong, age 47
Vice President – Corporate Excellence		3/98 to date
(Company service: 13 years)

Lorie Ann K. Nagata, age 45
Treasurer		12/00 to date
Manager, Management Accounting		5/98 to date
Assistant Treasurer		3/97 to 11/00
(Company service: 21 years)

Ernest T. Shiraki, age 56
Controller		5/89 to date
(Company service: 34 years)

Molly M. Egged, age 53
Secretary		10/89 to date
(Company service: 23 years)

HECO’s executive officers, with the exception of Robert A. Alm, Jackie Mahi Erickson, Charles M. Freedman, Thomas L. Joaquin, Chris M. Shirai, Thomas C. Simmons and Patricia U. Wong, are also officers and/or directors of MECO, HELCO or Renewable Hawaii, Inc. HECO executive officers Robert F. Clarke and Molly M. Egged are also officers of one or more of the affiliated nonutility HEI companies.

Board of Directors

The following is a list of current directors of HECO. The information is provided as of February 11, 2004.


Director	Age	Director since ^[2]
Robert F. Clarke	61	1990
T. Michael May	57	1995
Shirley J. Daniel ^[1]	50	2002
Diane J. Plotts ^[1]	68	1991
James K. Scott	52	1999
Anne M. Takabuki ^[1]	47	1997
Barry K. Taniguchi ^[1]	56	2001
Jeffrey N. Watanabe	60	1999

^[1]	Audit committee member.

^[2^]

Year indicates first year elected or appointed. All directors serve one year terms.

Anne M. Takabuki and Barry K. Taniguchi are the only nonemployee directors of HECO who are not directors of HEI. Ms. Takabuki has been President of Wailea Golf LLC and Kauai Golf LLC since October 1, 2003. At Wailea Golf Resort, Inc. she was President from March 2003 to September 2003 and Vice President/Secretary and

General Counsel from 1993 to February 2003. She also serves on the boards of Wailea Community Association and Kapiolani Medical Foundation and is a member of the advisory Board of Directors of MECO. Mr. Taniguchi is President of KTA Super Stores. He also serves on the boards of ASB, Puna Plantation Hawaii, Limited, K. Taniguchi, Ltd. and numerous not-for-profit boards, including Hawaii Community Foundation, Queen’s Health Systems and the Hawaii Island Economic Development Board, and is a member of the advisory Board of Directors of HELCO. Information concerning the directors of HECO who are also directors of HEI is set forth above under “HEI” and in the referenced sections of HEI’s 2004 Proxy Statement.

Committees of the HECO Board

During 2003, the Board of Directors of HECO had one standing committee, the Audit Committee, which was comprised of four nonemployee directors: Diane J. Plotts, Chairman, Shirley J. Daniel, Anne M. Takabuki and Barry K. Taniguchi. The Audit Committee holds such meetings as it deems advisable to review the financial operations of HECO. In 2003, the Audit Committee held six meetings to review various matters with management, the internal auditor and HECO’s independent auditors, including the activities of the internal auditor, the results of the annual audit by the independent auditors and the consolidated financial statements which are included in HECO’s 2002 Annual Report to Stockholder.

The independence of the HECO Audit Committee has been determined by the Board of Directors in accordance with the definition of independence in the Audit Committee charter and current standards sets forth in the New York Stock Exchange Listed Company Manual. Mr. Taniguchi, Dr. Daniel and Ms. Plotts have been determined by the Board of Directors to be the “audit committee financial experts” on the Audit Committee.

Attendance at meetings

In 2003, there were six regular bi-monthly meetings of the HECO Board of Directors. All incumbent directors attended at least 75% of the combined total number of meetings of the Board and the Audit Committee on which they served (during the period of their service).

Family relationships; director arrangements

There are no family relationships between any executive officer or director of HECO and any other executive officer or director of HECO, or any arrangement or understanding between any executive officer or director of HECO and any person pursuant to which the executive officer or director of HECO was selected.

Code of Conduct

In connection with its periodic review of corporate governance trends and best practices, the HEI Board of Directors adopted a Revised Code of Conduct, including the code of ethics for, among others, the chief executive officer and senior financial officers of HECO, which may be viewed on HEI’s website at www.hei.com. HECO also elects to disclose the information required by Form 8-K, Item 10, “Amendments to the registrant’s code of ethics, or waiver of a provision of the code of ethics,” through this website and such information will remain available on this website for at least a 12-month period. A copy of the Revised Code of Conduct may be obtained free of charge upon written request from the HEI Vice President-Administration & Corporate Secretary, P.O. Box 730, Honolulu, Hawaii 96808-0730.

ITEM 11.

EXECUTIVE COMPENSATION

HEI:

The information required under this item for HEI is incorporated by reference to the information under the captions “Board of Directors – How often did the Board of Directors meet in 2003?,” “Board of Directors – How are directors compensated?,” “Board of Directors – Do nonemployee directors receive a retirement benefit?,” “Committees of the Board – What committees has the Board established and how often did they meet?” and “Executive Compensation” in HEI’s 2004 Proxy Statement.

HECO:

Remuneration of HECO Directors

In 2003, Anne M. Takabuki and Barry K. Taniguchi were the only nonemployee HECO directors who were not also directors of HEI. Commencing May 1, 2003, they each received an annual cash retainer of $20,000 (paid quarterly) and 300 shares of HEI stock. In order to receive the fourth quarter installment, directors are required to have attended at least 75% of the combined total of all the Board and Committee meetings on which the director serves. The nonemployee HECO directors who were also nonemployee HEI directors received an annual cash retainer of $10,000, paid quarterly, for their service on the HECO Board. In 2003, the Chairman of the HECO Audit Committee was paid an additional annual cash retainer of $5,000. Employee members of the Board of Directors are not compensated for attendance at any meeting of the Board or Committees of the Board. Information concerning the directors of HECO who are also directors of HEI is set forth above under “HEI” and in the referenced sections of HEI’s 2004 Proxy Statement.

Ms. Plotts is the only nonemployee HECO director who will receive retirement benefits upon retirement from service as a director. Additional information concerning nonemployee director retirement benefits is incorporated by reference to the information under the caption “Board of Directors – Do nonemployee directors receive a retirement benefit?” in HEI’s 2004 Proxy Statement.

Summary compensation table

The following summary compensation table shows the annual and long-term compensation of the chief executive officer of HECO and the four other most highly compensated executive officers of HECO (collectively, the HECO Named Executive Officers) who served at the end of 2003. All compensation amounts presented for T. Michael May are the same amounts presented in HEI’s 2004 Proxy Statement.

SUMMARY COMPENSATION TABLE


		Annual Compensation			Long-term Compensation
				Other Annual Compen- sation⁽²⁾ ($)	Awards		Payouts	All Other Compen- sation⁽⁶⁾ ($)
Name and Principal Position	Year	Salary ($)	Bonus⁽¹⁾ ($)	Other Annual Compen- sation⁽²⁾ ($)	Restricted Stock Award⁽³⁾ ($)	Securities Underlying Options⁽⁴⁾ (#)	LTIP Payouts⁽⁵⁾ ($)	All Other Compen- sation⁽⁶⁾ ($)
T. Michael May President and Chief Executive Officer	2003 2002 2001	513,000 472,000 415,000	294,012 286,960 163,257	0 0 0	0 0 0	25,000 25,000 20,000	154,368 150,645 54,540	8,208 7,314 18,881
Robert A. Alm ⁽⁷⁾ Senior Vice President- Public Affairs	2003 2002 2001	238,000 223,000 100,000	165,996 57,227 30,367	0 0 0	0 0 0	6,000 0 0	NA NA NA	2,058 1,698 2,825
Thomas L. Joaquin Senior Vice President- Operations	2003 2002 2001	239,000 223,000 202,000	88,949 49,385 58,597	0 0 0	0 0 0	6,000 0 3,000	NA NA NA	4,787 4,475 11,745
Karl C. Stahlkopf ⁽⁸⁾ Senior Vice President- Energy Solutions and Chief Technology Officer	2003 2002	287,000 187,000	69,882 52,421	0 100,000	0 140,880	6,000 0	NA NA	8,018 4,929
Jackie Mahi Erickson Vice President & General Counsel	2003 2002 2001	194,000 181,000 175,000	90,922 38,869 47,844	0 0 0	0 0 0	3,000 0 3,000	NA NA NA	5,420 4,929 13,503

NA	Not applicable (not participants in the plan).

⁽¹⁾

The HECO Named Executive Officers are eligible for an incentive award under the Company’s annual Executive Incentive Compensation Plan (EICP). EICP bonus payouts are reflected as compensation for the year earned. Also includes special awards in 2003 to Mr. Alm for $100,000, Mr. Joaquin for $24,000 and Ms. Erickson for $36,000.

⁽²⁾	Covers a signing bonus of $100,000 for Mr. Stahlkopf for 2002.

⁽³⁾

On May 1, 2002, 3,000 shares of restricted stock were granted to Mr. Stahlkopf. On the date of grant, the closing price of HEI Common Stock was $46.96 on the New York Stock Exchange. Quarterly dividends on the 3,000 shares of restricted stock are paid to Mr. Stahlkopf. The 3,000 shares of restricted stock become unrestricted on May 1, 2007. On December 31, 2003, the restricted stock value was $142,110 based on the closing price of $47.37 per share on the New York Stock Exchange.

⁽⁴⁾	Options granted earn dividend equivalents as further described below under the headings “Option grants in last fiscal year” and “Aggregated option exercises and fiscal year-end option values.”

⁽⁵⁾	Long-Term Incentive Plan (LTIP) payouts are determined in the first quarter of each year for the three-year cycle ending on December 31 of the previous calendar year.

⁽⁶⁾

Represents amounts attributable each year by the Company for certain preretirement death benefits provided to the HECO Named Executive Officers. Additional information concerning these death benefits is incorporated by reference to the information under the caption “Executive Compensation – Compensation Committee Report on Executive Compensation – Other Compensation Plans” in HEI’s 2004 Proxy Statement.

⁽⁷⁾	Mr. Alm joined HECO as the Senior Vice President-Public Affairs on July 1, 2001.

⁽⁸⁾	Mr. Stahlkopf joined HECO as the Senior Vice President-Energy Solutions and Chief Technology Officer on May 1, 2002.

Option grants in last fiscal year

The following table presents information on the nonqualified stock options to acquire HEI common stock which were granted in 2003 to the executives named in the HECO Summary Compensation Table. The practice of granting stock options, which may include dividend equivalent shares, has been followed each year since 1987.

OPTION GRANTS IN LAST FISCAL YEAR


	Number of Securities Underlying Options Granted ⁽¹⁾(#)	Percent of Total Options Granted to Employees in Fiscal Year		Exercise Price ($/share)		Expiration Date	Grant Date Present Value ⁽²⁾($)
T. Michael May	25,000	11	%	$	40.98	April 21, 2013	$	227,500
Robert A. Alm	6,000	3			40.98	April 21, 2013		54,600
Thomas L. Joaquin	6,000	3			40.98	April 21, 2013		54,600
Karl C. Stahlkopf	6,000	3			40.98	April 21, 2013		54,600
Jackie Mahi Erickson	3,000	1			40.98	April 21, 2013		27,300

⁽¹⁾

These options vest in four equal annual installments. Additional dividend equivalent shares are granted at no additional cost throughout the four-year vesting period. Dividend equivalents are computed, as of each dividend record date, both with respect to the number of shares under the option and with respect to the number of dividend equivalent shares previously credited to the participant and not issued during the period prior to the dividend record date. Accelerated vesting is provided in the event a change-in-control occurs. No stock appreciation rights have been granted under the HEI’s stock option plans.

⁽²⁾

Based on a Binomial Option Pricing Model, which is a variation of the Black-Scholes Option Pricing Model calculated by the HEI Compensation Committee’s independent compensation consulting firm. For the stock options granted on April 21, 2003, with a 10-year option period, an exercise price of $40.98 which is equal to the fair market value on the date of grant, and with additional dividend equivalent shares granted for the first four years of the option, the Binomial Value adjusted for forfeiture risk is $9.10 per share. The following assumptions were used in the model: Stock Price: $40.98; Term: 10 years; Volatility: 0.1841; Risk-Free Interest Rate: 4.37 %; and Dividend Yield: 6.64%. The following were the valuation results: Binomial Option Value: $4.86; Dividend Credit Value: $4.24; and Total Value: $9.10.

In calculating the grant date present values set forth in the table, the volatility and dividend yield were based on the monthly closing stock prices and dividends for the three-year period preceding the grant date. The risk-free interest rate was fixed on the date of grant at the rate of return on a stripped U.S. Treasury bill with a term to maturity approximately equal to the options’ expected life. Dividend equivalents are payable on the options for a period of four years. The value of the dividend equivalents was determined on the basis of the dividend yield, using the monthly closing stock prices and dividends for the three-year period preceding the grant date. The use of different assumptions can produce significantly different estimates of the present value of options. Consequently, the grant date present value set forth in the table is only theoretical and may not accurately represent present value. The actual value, if any, an optionee will realize will depend on the excess of the market value of the HEI Common Stock over the exercise price on the date the option is exercised, plus the value of the dividend equivalents.

Aggregated option exercises and fiscal year-end option values

The following table shows the stock options, including dividend equivalents, exercised by the HECO Named Executive Officers in 2003. Also shown is the number of securities underlying unexercised options and the value of unexercised in the money options, including dividend equivalents, at the end of 2003. HEI granted dividend equivalents to all HECO Named Executive Officers as part of the stock option grant, except Mr. Joaquin’s 1995 stock option grant.

Dividend equivalents permit a participant who exercises a stock option to obtain at no additional cost, in addition to the option shares, the amount of dividends declared between the grant and the exercise of the option during the vesting period. Dividend equivalents are computed as of each dividend record date throughout the four-year vesting period, both with respect to the number of shares under the option and the number of dividend equivalent shares previously credited to the HECO Named Executive Officer, which have not been exercised/issued during the period prior to the dividend record date.

AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND

FISCAL YEAR-END OPTION VALUES


Name	Shares Acquired On Exercise (#)	Dividend Equivalents Acquired On Exercise (#)	Value Realized On Options ($)	Value Realized On Dividend Equivalents ($)	Number of Securities Underlying Unexercised Options (Including Dividend Equivalents) at Fiscal Year-End	Value of Unexercised In the Money Options (Including Dividend Equivalents) at Fiscal Year-End ⁽¹⁾
Name	Shares Acquired On Exercise (#)	Dividend Equivalents Acquired On Exercise (#)	Value Realized On Options ($)	Value Realized On Dividend Equivalents ($)	Exercisable/ Unexercisable (#)	Exercisable/ Unexercisable ($)
T. Michael May	10,000	3,042	74,500	129,788	50,686 /64,934	976,510 /731,803
Robert A. Alm	—	—	—	—	— /6,267	— /50,990
Thomas L. Joaquin	—	—	—	—	12,637 / 8,033	236,783 / 80,770
Karl C. Stahlkopf	—	—	—	—	— / 6,267	— / 50,990
Jackie Mahi Erickson	—	—	—	—	1,861 / 4,900	34,819 / 55,275

⁽¹⁾	Values based on the closing price of $47.37 per share on the New York Stock Exchange on December 31, 2003.

Long-Term Incentive Plan awards table

A Long-Term Incentive Plan award made to Mr. May was the only such award made to the HECO Named Executive Officers in 2003. Additional information required under this item is incorporated by reference to the information under the caption “Executive Compensation – Long-Term Incentive Plan (LTIP) Award” in HEI’s 2004 Proxy Statement.

Pension plans

Each of the HECO Named Executive Officers participates in the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries (the Retirement Plan). In addition, Mr. May (but not the other HECO Named Executive Officers) participates in certain supplemental pension plans sponsored by HEI. For additional information required under this item for Mr. May, see the information under the caption “Executive Compensation – Pension Plans” in HEI’s 2004 Proxy Statement.

The Retirement Plan provides a monthly retirement pension for life. Additional information required under this item is incorporated by reference to the information under the caption “Executive Compensation – Pension Plans” in HEI’s 2004 Proxy Statement. As of December 31, 2003, the HECO Named Executive Officers had the following number of years of credited service under the Retirement Plan: Mr. May, 11 years; Mr. Alm, 2 years; Mr. Joaquin, 30 years; Mr. Stahlkopf, 1 year; and Ms. Erickson, 22 years.

Change-in-Control Agreements

HECO does not have change-in-control agreements with any of the HECO Named Executive Officers. Mr. May is the only HECO Named Executive Officer with whom HEI has a Change-in-Control Agreement. Additional information required under this item is incorporated by reference to the information under the caption “Executive Compensation – Change-in-Control Agreements” in HEI’s 2004 Proxy Statement.

Executive Management Compensation

The HEI Compensation Committee, composed of six independent nonemployee directors of HEI, approves executive compensation for the HECO Named Executive Officers. The information required to be disclosed concerning the Compensation Committee is incorporated herein by reference to the information under the captions “Committees of the Board” and “Executive Compensation – Compensation Committee Report on Executive Compensation” in HEI’s 2004 Proxy Statement. Actions of the HEI Compensation Committee are subject to ratification by the full HEI and HECO Boards of Directors (excluding any affected individuals).

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

HEI:

The information required under this item is incorporated by reference to the information under the captions “Stock Ownership Information – How much stock do the Company’s directors and executive officers own?” and “Stock Ownership Information – Does anyone own more than 5% of the Company’s stock?” in HEI’s 2004 Proxy Statement and “Market for Registrant’s Common Equity and Related Stockholder Matters–equity compensation plan information” herein.

HECO:

HEI owns all of HECO’s common stock, which is HECO’s only class of securities generally entitled to vote on matters requiring shareholder approval. HECO has also issued and has outstanding various series of preferred stock, the holders of which, upon certain defaults in dividend payments, have the right to elect a majority of the directors of HECO.

The following table shows the shares of HEI common stock beneficially owned by each HECO director (other than those who are also directors of HEI), by each HECO Named Executive Officer (other than Mr. May, who is a named executive officer of HEI) and by all HECO directors and all HECO executive officers as a group, as of February 11, 2004, based on information furnished by the respective individuals.


Amount of Common Stock and Nature of Beneficial Ownership
Name of Individual or Group	Sole Voting or Investment Power	Shared Voting or Investment Power ⁽¹⁾	Other Beneficial Ownership ⁽²⁾	Stock Options ⁽³⁾	Total
Directors
Anne M. Takabuki	2,969	—	—	—	2,969
Barry K. Taniguchi	—	2,345	—	—	2,345

Other HECO Named Executive Officers
Robert A. Alm	2,287	—	—	—	2,287
Thomas L. Joaquin	6,686	1,599	35	12,658	20,978
Karl C. Stahlkopf	3,537	—	—	—	3,537
Jackie Mahi Erickson	5,036	1,298	—	893	7,227
All directors and executive Officers as a group (21 persons)	78,749	15,089	3,308	161,539	258,685	*

HECO directors Clarke, Daniel, May, Plotts, Scott and Watanabe, who also serve on the HEI Board of Directors, are not shown separately in this table, but are included in the total for all HECO directors and executive officers as a group. The information required as to these directors is incorporated by reference to the information under the caption “Stock Ownership Information – How much stock do the Company’s directors and executive officers own?” in HEI’s 2004 Proxy Statement. The number of shares of common stock beneficially owned by any HECO director or by all HECO directors and officers as a group does not exceed 1% of the outstanding common stock of HEI.

⁽¹⁾	Shares registered in name of the individual and spouse.

⁽²⁾	Shares owned by spouse, children or other relatives sharing the home of the director or officer in which the director or officer disclaims personal interest.

⁽³⁾	Stock options, including accompanying dividend equivalents shares, exercisable within 60 days after February 11, 2004, under the 1987 Stock Option and Incentive Plan.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

HEI:

The information required under this item is incorporated by reference to the information under the captions “Indebtedness of Management” and “Transactions with Directors and Executive Officers” in HEI’s 2004 Proxy Statement.

HECO:

Information required under this item for HECO directors and officers who are also directors or officers of HEI is incorporated by reference to the information under the captions “Indebtedness of Management” and “Transactions with Directors and Executive Officers” in HEI’s 2004 Proxy Statement. In addition, Karl C. Stahlkopf was indebted to HECO in the amount of $162,500 for an employee relocation loan made to him on May 22, 2002, prior to the enactment of the Sarbanes-Oxley Act of 2002. The loan was interest free with the principal balance paid by the due date of May 22, 2003. Director Jeffrey Watanabe is a partner in the law firm of Watanabe Ing Kawashima & Komeiji LLP which performed legal services for HEI and certain of its subsidiaries (including HECO and HELCO) during 2003.

ITEM 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

HEI:

The information required under this item is incorporated by reference to the relevant information under the caption “Audit Committee Report” in HEI’s 2004 Proxy Statement (but no other part of the “Audit Committee Report” is incorporated by reference).

HECO:

Certain information required as to HECO under this item is included in the disclosures for HEI under the caption “Audit Committee Report” in HEI’s 2004 Proxy Statement, which is incorporated by reference above.

Fees of HECO’s Principal Accountant

The following table sets forth the aggregate fees billed to HECO for the years ended December 31, 2003 and 2002 by KPMG LLP, HECO’s independent auditor:


	2003		2002
Audit fees (principally consisted of fees associated with the audit and quarterly reviews of the consolidated financial statements, issuances of letters to underwriters, accounting consultations on matters reflected in the financial statements, review of registration statements, and issuance of consents)	$	365,000	$	300,000
Audit related fees (principally consisted of fees associated with the audit of the financial statements of certain employee benefit plans)		9,000		8,000
Tax fees		—		—
All other fees		—		—

	$	374,000	$	308,000

Pre-approval Policies

The HECO Audit Committee approved and adopted preapproval policies and procedures for nonaudit services proposed to be performed by HECO’s independent auditor. The policies and procedures were implemented in 2002. Departmental requests for nonaudit services are reviewed by senior management and, once approved, are forwarded to the Chair of the Audit Committee for preapproval. The Audit Committee ratifies the Chair’s preapproval at its next scheduled meeting. In addition, the HECO Audit Committee reviewed the professional fees billed by KPMG LLP and determined that the provision of nonaudit services was compatible with the maintenance of the auditors’ independence.

PART IV

ITEM 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a)(1) Financial statements

The following financial statements for HEI and HECO are included in this report on the pages indicated below:


	Pages in HEI’s Annual Report and HECO’s Consolidated Financial Statements
	HEI	HECO
Independent Auditors’ Report	39	39
Consolidated Statements of Income, Years ended December 31, 2003, 2002 and 2001	40	1
Consolidated Statements of Retained Earnings, Years ended December 31, 2003, 2002 and 2001	NA	1
Consolidated Balance Sheets, December 31, 2003 and 2002	41	2
Consolidated Statements of Capitalization, December 31, 2003 and 2002	NA	3-4
Consolidated Statements of Changes in Stockholders’ Equity, Years ended December 31, 2003, 2002 and 2001	42	NA
Consolidated Statements of Cash Flows, Years ended December 31, 2003, 2002 and 2001	43	5
Notes to Consolidated Financial Statements	44-88	6-38

NA	Not applicable.

(a)(2) Financial statement schedules

The following financial statement schedules for HEI and HECO are included in this report on the pages indicated below:

NA	Not applicable.

Certain schedules, other than those listed, are omitted because they are not required, or are not applicable, or the required information is shown in the consolidated financial statements (including the notes) included in HEI’s Consolidated Financial Statements and HECO’s Consolidated Financial Statements, which are included in this report.

(a)(3) Exhibits

Exhibits for HEI and HECO and their subsidiaries are listed in the “Index to Exhibits” found on pages 87 through 97 of this Form 10-K/A. The exhibits listed for HEI and HECO are listed in the index under the headings “HEI” and “HECO,” respectively, except that the exhibits listed under “HECO” are also considered exhibits for HEI.

(b) Reports on Form 8-K

HEI and HECO:

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


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

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

November 25, 2003 (November 25, 2003)	HEI/HECO	Item 5. HEI’s November 25, 2003 news release (HEI to webcast and teleconference financial analyst presentation on Tuesday, December 2, 2003)

December 10, 2003 (December 10, 2003)	HEI/HECO	Item 5. Pension and other postretirement benefits and HELCO power situation updates

December 31, 2003 (January 2, 2004)	HEI	Item 5. Disposition of certain debt securities update

January 6, 2004 (January 8, 2004)	HEI/HECO	Item 5. HEIPC and Settlement of Maalaea Units 12 and 13 notice and finding of violation updates

January 13, 2004 (January 14, 2004)	HEI/HECO	Item 5. HEI’s January 13, 2004 news release (HEI to webcast and teleconference 2003 year-end earnings on Tuesday, January 20, 2004)

January 20, 2004 (January 21, 2004)	HEI/HECO	Items 5 and 12. HEI’s January 20, 2004 news release (HEI reports 2003 year-end and fourth quarter earnings) and pension and other postretirement benefits information

February 26, 2004 (February 26, 2004)	HEI/HECO	Item 7. HEI’s 2003 Annual Report to Shareholders, HECO’s Consolidated 2003 Financial Statements and 906 certifications

[KPMG LLP letterhead]

Independent Auditors’ Report

The Board of Directors and Stockholders

Hawaiian Electric Industries, Inc.:

Under date of February 11, 2004, we reported on the consolidated balance sheets of Hawaiian Electric Industries, Inc. and subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of income, changes in stockholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2003, as contained in the 2003 annual report to stockholders. These consolidated financial statements and our report thereon are incorporated by reference in the Company’s annual report on Form 10-K/A for the year 2003. In connection with our audits of the aforementioned consolidated financial statements, we also audited the related financial statement schedules as listed in the accompanying index under Item 15.(a)(2). These financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statement schedules based on our audits.

In our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

As discussed in note 1 of notes to consolidated financial statements, effective January 1, 2002, the Company changed its method of accounting for goodwill and other intangible assets and for stock-based compensation.

/s/ KPMG LLP

Honolulu, Hawaii

February 11, 2004

[KPMG LLP letterhead]

Independent Auditors’ Report

The Board of Directors and Stockholder

Hawaiian Electric Company, Inc.:

Under date of February 11, 2004, we reported on the consolidated balance sheets and consolidated statements of capitalization of Hawaiian Electric Company, Inc. (a subsidiary of Hawaiian Electric Industries, Inc.) and subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of income, retained earnings and cash flows for each of the years in the three-year period ended December 31, 2003. These consolidated financial statements and our report thereon are incorporated by reference in the Company’s annual report on Form 10-K/A for the year 2003. In connection with our audits of the aforementioned consolidated financial statements, we also audited the related financial statement schedule as listed in the accompanying index under Item 15.(a)(2). The financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statement schedule based on our audits.

In our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ KPMG LLP

Honolulu, Hawaii

February 11, 2004

Hawaiian Electric Industries, Inc.

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)

CONDENSED BALANCE SHEETS


	December 31,
(in thousands)	2003		2002
Assets
Cash and equivalents	$	12,009	$	25,059
Advances to and notes receivable from subsidiaries		6,000		5,600
Available-for-sale investment securities		12,124		7,971
Accounts receivable		11,970		1,593
Property, plant and equipment, net		1,815		2,089
Deferred income tax assets		16,289		13,110
Other assets		5,281		4,152
Net assets of discontinued operations		—		787
Investments in subsidiaries, at equity		1,532,101		1,512,423

	$	1,597,589	$	1,572,784

Liabilities and stockholders’ equity
Liabilities
Accounts payable	$	8,350	$	8,108
Notes payable to subsidiaries		14,371		10,922
Long-term debt, net		365,000		401,000
Loan from HEI Preferred Funding, LP (8.36% due in 2017)		103,000		103,000
Other		12,845		3,454
Net liabilities of discontinued operations		4,992		—

		508,558		526,484

Stockholders’ equity
Preferred stock, no par value, authorized 10,000 shares; issued: none		—		—
Common stock, no par value, authorized 100,000 shares; issued and outstanding: 37,919 shares and 36,809 shares		888,431		839,503
Retained earnings		197,774		176,118
Accumulated other comprehensive income		2,826		30,679

		1,089,031		1,046,300

	$	1,597,589	$	1,572,784

Note to Balance Sheets
Long-term debt consisted of the following:
Promissory notes, 4.0 - 7.6%, due in various years from 2004 through 2014	$	365,000	$	301,000
Promissory note, 5.5%, paid in 2003		—		100,000

	$	365,000	$	401,000

The aggregate payments of principal required subsequent to December 31, 2003 on long-term debt are $1 million in 2004, $37 million in 2005, $110 million in 2006, $10 million in 2007 and $50 million in 2008.

As of December 31, 2003, HEI has a General Agreement of Indemnity in favor of SAFECO Insurance Company for losses in connection with any insurance/surety bonds they issue to HEI, including $10 million in mail insurance, a $1 million transfer agent errors and omissions bond and a $0.5 million self-insured automobile bond.

HEI guarantees payment by HEI Capital Trust I (the Trust) of distributions on the trust securities insofar as the Trust has funds sufficient for the payment of such distributions. HEI guarantees payment by HEI Preferred Funding, LP (the Partnership) of distributions on the Partnership Preferred Securities insofar as such distributions have been declared by the Partnership and the Partnership has sufficient funds for the payment of such distributions.

Hawaiian Electric Industries, Inc.

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (continued)

HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)

CONDENSED STATEMENTS OF INCOME


	Years ended December 31,
(in thousands)	2003			2002			2001
Revenues ^{1, 2}	$	10,765		$	(3,881	)	$	(5,338	)
Equity in income from continuing operations of subsidiaries		142,354			152,725			143,730

		153,119			148,844			138,392

Expenses:
Operating, administrative and general		15,927			15,633			10,481
Depreciation of property, plant and equipment		403			891			1,047
Taxes, other than income taxes		345			460			472

		16,675			16,984			12,000

Operating income		136,444			131,860			126,392
Interest expense		33,993			37,576			43,539

Income from continuing operations before income tax benefits		102,451			94,284			82,853
Income tax benefits		15,597			23,933			24,893

Income from continuing operations		118,048			118,217			107,746
Loss from discontinued subsidiary operations		(3,870	)		—			(24,041	)

Net income	$	114,178		$	118,217		$	83,705

¹	2003 revenues include $9.3 million from the settlement of lawsuits in the fourth quarter of 2003.

2002 and 2001 revenues include $4.5 million and $8.7 million, respectively, of writedowns of the income notes that HEI purchased in connection with the termination of ASB’s investment in trust certificates in 2001. There were no writedowns of the income notes in 2003. See “Disposition of certain debt securities” in “Business–Bank–American Savings Bank, F.S.B.”

The Company’s financial reporting policy for income tax allocations is based upon a separate entity concept whereby each subsidiary provides income tax expense (or benefits) as if each were a separate taxable entity. The difference between the aggregate separate tax return income tax provisions and the consolidated financial reporting income tax provision is charged or credited to HEI’s separate tax provision.

Hawaiian Electric Industries, Inc.

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (continued)

HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)

CONDENSED STATEMENTS OF CASH FLOWS


	Years ended December 31,
(in thousands)	2003			2002			2001
Cash flows from operating activities
Income from continuing operations	$	118,048		$	118,217		$	107,746
Adjustments to reconcile income from continuing operations to net cash provided by operating activities
Equity in net income of continuing subsidiaries		(142,354	)		(152,725	)		(143,730	)
Common stock dividends/distributions received from subsidiaries		89,722			78,599			62,944
Depreciation of property, plant and equipment		403			891			1,047
Other amortization		448			500			579
Writedowns of income notes		—			4,499			8,652
Deferred income taxes		(4,769	)		(6,495	)		(6,778	)
Changes in assets and liabilities
Decrease (increase) in accounts receivable		(10,377	)		239			(638	)
Increase (decrease) in accounts payable		242			31			(346	)
Increase (decrease) in taxes accrued		10,787			10,988			(47,603	)
Changes in other assets and liabilities		6,669			5,266			4,709

Net cash provided by (used in) operating activities		68,819			60,010			(13,418	)

Cash flows from investing activities
Net decrease (increase) in advances to and notes receivable from subsidiaries		(400	)		42,697			(39,533	)
Purchase of investments		—			—			(27,929	)
Capital expenditures		(131	)		(396	)		(916	)
Additional investments in subsidiaries		(145	)		(325	)		(1,424	)
Other		17			480			16

Net cash provided by (used in) investing activities		(659	)		42,456			(69,786	)

Cash flows from financing activities
Net increase in notes payable to subsidiaries with original maturities of three months or less		3,449			4,608			2,675
Proceeds from issuance of long-term debt		100,000			—			100,000
Repayment of long-term debt		(136,000	)		(59,500	)		(60,500	)
Net proceeds from issuance of common stock		29,824			32,451			78,937
Common stock dividends		(75,119	)		(73,412	)		(67,015	)

Net cash provided by (used in) financing activities		(77,846	)		(95,853	)		54,097

Net cash provided by (used in) discontinued operations		(3,364	)		(709	)		47,585

Net increase (decrease) in cash and equivalents		(13,050	)		5,904			18,478
Cash and equivalents, January 1		25,059			19,155			677

Cash and equivalents, December 31	$	12,009		$	25,059		$	19,155

Supplemental disclosures of noncash activities:

In 2003, 2002 and 2001, $0.9 million, $0.8 million and $0.8 million, respectively, of HEI advances to HEIDI were converted to equity in noncash transactions.

Under the HEI Dividend Reinvestment and Stock Purchase Plan, common stock dividends reinvested by shareholders in HEI common stock in noncash transactions amounted to $17 million in 2003, $17 million in 2002 and $16 million in 2001.

Hawaiian Electric Industries, Inc.

and Hawaiian Electric Company, Inc.

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

Years ended December 31, 2003, 2002 and 2001


Col. A	Col. B		Col. C					Col. D			Col. E
(in thousands)			Additions
Description	Balance at begin -ning of period		Charged to costs and expenses		Charged to other accounts			Deductions			Balance at end of period
2003
Allowance for uncollectible accounts–Hawaiian Electric Company, Inc. and subsidiaries	$	998	$	1,721	$	803	^(a)	$	2,615	^(b)	$	907

Allowance for uncollectible interest (ASB)	$	730		—		—		$	575		$	155

Allowance for losses for loans receivable (ASB)	$	45,435	$	3,075	$	2,469	^(a)	$	6,694	^(b)	$	44,285


2002
Allowance for uncollectible accounts–Hawaiian Electric Company, Inc. and subsidiaries	$	1,260	$	1,444	$	1,286	^(a)	$	2,992	^(b)	$	998

Allowance for uncollectible interest (ASB)	$	2,710		—		—		$	1,980		$	730

Allowance for losses for loans receivable (ASB)	$	42,224	$	9,750	$	1,205	^(a)	$	7,744	^(b)	$	45,435


2001
Allowance for uncollectible accounts–Hawaiian Electric Company, Inc. and subsidiaries	$	939	$	1,930	$	1,246	^(a)	$	2,855	^(b)	$	1,260

Allowance for uncollectible interest (ASB)	$	2,978		—		—		$	268		$	2,710

Allowance for losses for loans receivable (ASB)	$	37,449	$	12,500	$	1,898	^(a)	$	9,623	^(b)	$	42,224

^(a)	Primarily bad debts recovered.

^(b)	Bad debts charged off.

INDEX TO EXHIBITS

The exhibits designated by an asterisk (*) are filed herein. The exhibits not so designated are incorporated by reference to the indicated filing. A copy of any exhibit may be obtained upon written request for a $0.20 per page charge from the HEI Shareholder Services Division, P.O. Box 730, Honolulu, Hawaii 96808-0730.


Exhibit no.		Description
HEI:

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

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

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

3(ii)		HEI’s Amended and Restated By-Laws. (Exhibit 3(ii) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001, File No. 1-8503).

4.1		Agreement to provide the SEC with instruments which define the rights of holders of certain long-term debt of HEI and its subsidiaries (Exhibit 4.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-8503).

4.2(a)		Rights Agreement, dated as of October 28, 1997, between HEI and Continental Stock Transfer & Trust Company, as Rights Agent, which includes as Exhibit B thereto the Form of Rights Certificates (Exhibit 1 to HEI’s Form 8-A, dated October 28, 1997, File No. 1-8503).

4.2(b)		First Amendment, dated as of May 7, 2003, to Rights Agreement (dated as of October 28, 1997) between HEI and Continental Stock Transfer & Trust Company, as Rights Agent (Exhibit 4.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2003, File No. 1-8503).

4.3		Indenture, dated as of October 15, 1988, between HEI and Citibank, N.A., as Trustee (Exhibit 4 to Registration No. 33-25216).

4.4(a)		First Supplemental Indenture dated as of June 1, 1993 between HEI and Citibank, N.A., as Trustee, to Indenture dated as of October 15, 1988 between HEI and Citibank, N.A., as Trustee (Exhibit 4(a) to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1993, File No. 1-8503).

4.4(b)		Second Supplemental Indenture dated as of April 1, 1999 between HEI and Citibank, N.A., as Trustee, to Indenture dated as of October 15, 1988 between HEI and Citibank, N.A., as Trustee (Exhibit 4.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1999, File No. 1-8503).

4.4(c)		Third Supplemental Indenture dated as of August 1, 2002 between HEI and Citibank, N.A., as Trustee, to Indenture dated as of October 15, 1988 between HEI and Citibank, N.A., as Trustee (Exhibit 4 to HEI’s Current Report on Form 8-K dated August 16, 2002, File No. 1-8503).


Exhibit no.		Description

4.5(a)		Pricing Supplement No. 11 to Registration Statement on Form S-3 of HEI (Registration No. 33-58820) filed on December 1, 1995 in connection with the sale of Medium-Term Notes, Series B (Exhibit 4.8 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1995, File No. 1-8503).

4.5(b)		Pricing Supplement No. 12 to Registration Statement on Form S-3 of HEI (Registration No. 33-58820) filed on February 12, 1996 in connection with the sale of Medium-Term Notes, Series B (Exhibit 4.9 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1995, File No. 1-8503).

4.5(c)		Pricing Supplements Nos. 13 through 14 to Registration Statement on Form S-3 of HEI (Registration No. 33-58820) filed on September 26, 1997 in connection with the sale of Medium-Term Notes, Series B.

4.5(d)		Pricing Supplement No. 15 to Registration Statement on Form S-3 of HEI (Registration No. 33-58820) filed on September 29, 1997 in connection with the sale of Medium-Term Notes, Series B.

4.5(e)		Pricing Supplement No. 16 to Registration Statement on Form S-3 of HEI (Registration No. 33-58820) filed on September 30, 1997 in connection with the sale of Medium-Term Notes, Series B.

4.5(f)		Pricing Supplement No. 17 to Registration Statement on Form S-3 of HEI (Registration No. 33-58820) filed on October 2, 1997 in connection with the sale of Medium-Term Notes, Series B.

4.5(g)		Pricing Supplement No. 24 to Registration Statement on Form S-3 of HEI (Registration No. 33-58820) filed on June 10, 1998 in connection with the sale of Medium-Term Notes, Series B.

4.5(h)		Pricing Supplement No. 1 to Registration Statement on Form S-3 of HEI (Registration No. 333-73225) filed on May 3, 1999 in connection with the sale of Medium-Term Notes, Series C.

4.5(i)		Pricing Supplement No. 3 to Registration Statement on Form S-3 of HEI (Registration No. 333-73225) filed on April 5, 2001 in connection with the sale of Medium-Term Notes, Series C.

4.5(j)		Pricing Supplement No. 1 to Registration Statement on Form S-3 of HEI (Registration No. 333-87782) filed on March 5, 2003 in connection with the sale of Medium-Term Notes, Series D.

4.5(k)		Pricing Supplement No. 2 to Registration Statement on Form S-3 of HEI (Registration No. 333-87782) filed on March 5, 2003 in connection with the sale of Medium-Term Notes, Series D.

4.6		Amended and Restated Agreement of Limited Partnership of HEI Preferred Funding, LP dated as of February 1, 1997 (Exhibit 4(e) to HEI’s Current Report on Form 8-K dated February 4, 1997, File No. 1-8503).

4.7		Amended and Restated Trust Agreement of Hawaiian Electric Industries Capital Trust I (HEI Trust I) dated as of February 1, 1997 (Exhibit 4(f) to HEI’s Current Report on Form 8-K dated February 4, 1997, File No. 1-8503).


Exhibit no.		Description

4.8		Junior Indenture between HEI and The Bank of New York, as Trustee, dated as of February 1, 1997 (Exhibit 4(i) to HEI’s Current Report on Form 8-K dated February 4, 1997, File No. 1-8503).

4.9		Officers’ Certificate in connection with issuance of 8.36% Junior Subordinated Debenture, Series A, Due 2017 under Junior Indenture of HEI (Exhibit 4(l) to HEI’s Current Report on Form 8-K dated February 4, 1997, File No. 1-8503).

4.10		8.36% Trust Originated Preferred Security (Liquidation Amount $25 Per Trust Preferred Security) of HEI Trust I (Exhibit 4(m) to HEI’s Current Report on Form 8-K dated February 4, 1997, File No. 1-8503).

4.11		8.36% Junior Subordinated Debenture Series A, Due 2017, of HEI (Exhibit 4(n) to HEI’s Current Report on Form 8-K dated February 4, 1997, File No. 1-8503).

4.12		Trust Preferred Securities Guarantee Agreement with respect to HEI Trust I dated as of February 1, 1997 (Exhibit 4(o) to HEI’s Current Report on Form 8-K dated February 4, 1997, File No. 1-8503).

4.13		Partnership Guarantee Agreement with respect to the Partnership dated as of February 1, 1997 (Exhibit 4(p) to HEI’s Current Report on Form 8-K dated February 4, 1997, File No. 1-8503).

4.14		Affiliate Investment Instruments Guarantee Agreement with respect to 8.36% Junior Subordinated Debenture of HEIDI dated as of February 1, 1997 (Exhibit 4(q) to HEI’s Current Report on Form 8-K dated February 4, 1997, File No. 1-8503).

4.15		Certificate Evidencing Trust Common Securities of HEI Trust I dated February 4, 1997 (Exhibit 4.12 to the Quarterly Report on Form 10-Q of HEI Trust I and the Partnership, File No. 1-8503-02, for the quarter ended March 31, 1997).

4.16		Certificate Evidencing Partnership Preferred Securities of the Partnership dated February 4, 1997 (Exhibit 4.13 to the Quarterly Report on Form 10-Q of HEI Trust I and the Partnership, File No. 1-8503-02, for the quarter ended March 31, 1997).

10.1		PUC Order Nos. 7070, 7153, 7203 and 7256 in Docket No. 4337, including copy of “Conditions for the Merger and Corporate Restructuring of Hawaiian Electric Company, Inc.” dated September 23, 1982 (Exhibit 10 to Amendment No. 1 to Form U-1).

10.2		Regulatory Capital Maintenance/Dividend Agreement dated May 26, 1988, between HEI, HEIDI and the Federal Savings and Loan Insurance Corporation (by the Federal Home Loan Bank of Seattle) (Exhibit (28)-2 to HEI’s Current Report on Form 8-K dated May 26, 1988, File No. 1-8503).

10.3		OTS letter regarding release from Part II.B. of the Regulatory Capital Maintenance/Dividend Agreement dated May 26, 1988 (Exhibit 10.3(a) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-8503).

10.4		Executive Incentive Compensation Plan (Exhibit 4.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2003, File No. 1-8503)..

10.5		HEI Executives’ Deferred Compensation Plan (Exhibit 10.5 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1990, File No. 1-8503).


Exhibit no.		Description

10.6		1987 Stock Option and Incentive Plan of HEI as amended and restated effective January 21, 2003 (Exhibit 10.2 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2003, File No. 1-8503).

10.7		HEI Long-Term Incentive Plan (Exhibit 10.7 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8503)..

10.8(a)		HEI Supplemental Executive Retirement Plan effective as of January 1, 1989 (Exhibit 10.8(a) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8503).

10.8(b)		HEI Excess Pay Supplemental Executive Retirement Plan (Exhibit 10.8(b) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8503).

10.9		HEI Excess Benefit Plan effective as of January 1, 1994 (Exhibit 10.9 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8503).

10.10		Form of Change-in-Control Agreement (Exhibit 10.14 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989, File No. 1-8503).

10.11		Nonemployee Director Retirement Plan, effective as of October 1, 1989 (Exhibit 10.15 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989, File No. 1-8503).

10.12		HEI 1990 Nonemployee Director Stock Plan, As Amended and Restated (Exhibit 10.12 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8503).

10.13		HEI Nonemployee Directors’ Deferred Compensation Plan (Exhibit 10.14 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1990, File No. 1-8503).

10.14		Form of HEI and HECO Executives’ Deferred Compensation Agreement. The agreement pertains to and is substantially identical for all the HEI and HECO executive officers (Exhibit 10.15 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1991, File No. 1-8503).

10.15		Employment Separation Agreement by and between Robert F. Mougeot and HEI, and its subsidiary and affiliated entities and the shareholders, directors, officers, employees and agents of HEI and its subsidiary and affiliated entities effective November 24, 2002 (Exhibit 10.15 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8503).

10.16		HEI Executive Death Benefit Plan of HEI and Participating Subsidiaries effective September 1, 2001 (Exhibit 10.16 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8503).

*11		Computation of Earnings per Share of Common Stock. Filed herein as page 98.

*12		Computation of Ratio of Earnings to Fixed Charges. Filed herein as pages 99 and 100.


Exhibit no.		Description

13		HEI’s 2003 Annual Report to Shareholders (HEI Exhibit 13 to HEI’s Current Report on Form 8-K dated February 26, 2004, File No. 1-8503).

18		KPMG LLP letter re: change in accounting principle (Exhibit 18.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 1-8503).

*21		Subsidiaries of HEI. Filed herein as page 101.

*23.1		Accountants’ Consent. Filed herein as page 102.

*31.1		Certification Pursuant to 13a-14 of the Securities and Exchange Act of 1934, as Adopted by Section 302 of the Sarbanes-Oxley Act of 2002 of Robert F. Clarke (HEI Chief Executive Officer). Filed herein as page 104.

*31.2		Certification Pursuant to 13a-14 of the Securities and Exchange Act of 1934, as Adopted by Section 302 of the Sarbanes-Oxley Act of 2002 of Eric K. Yeaman (HEI Chief Financial Officer). Filed herein as page 105.

*32.1		Written Statement Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002 of Robert F. Clarke, HEI Chief Executive Officer. Filed herein as page 106.

*32.2		Written Statement Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002 of Eric K. Yeaman, HEI Chief Financial Officer. Filed herein as page 107.

*99.1		Amendment 2003-2 to the Hawaiian Electric Industries Retirement Savings Plan for incorporation by reference in the Registration Statement on Form S-8 (Regis. No. 333-02103).

*99.2		Ninth Amendment to Trust Agreement between HEI and Fidelity Management Trust Company made and entered into February 2, 2004.
HECO:

3(i).1		HECO’s Certificate of Amendment of Articles of Incorporation (Exhibit 3.1 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1988, File No. 1-4955).

3(i).2		Articles of Amendment to HECO’s Amended Articles of Incorporation (Exhibit 3.1(b) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989, File No 1-4955).

3(i).3		Articles of Amendment to HECO’s Amended Articles of Incorporation (Exhibit 3(i).4 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1998, File No 1-4955).

3(ii)		HECO’s By-Laws (Exhibit 3.2 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1988, File No. 1-4955).

4.1		Agreement to provide the SEC with instruments which define the rights of holders of certain long-term debt of HECO, HELCO and MECO (Exhibit 4.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-4955).

4.2		Amended and Restated Trust Agreement of HECO Capital Trust I (HECO Trust I) dated as of March 1, 1997 (Exhibit 4(c) to HECO’s Current Report on Form 8-K dated March 27, 1997, File No. 1-4955).


Exhibit no.		Description

4.3		HECO Junior Indenture with The Bank of New York, as Trustee, dated as of March 1, 1997 (Exhibit 4(d) to HECO’s Current Report on Form 8-K dated March 27, 1997, File No. 1-4955).

4.4		8.05% Cumulative Quarterly Income Preferred Security (liquidation preference $25 per preferred security) of HECO Trust I (Exhibit 4(e) to HECO’s Current Report on Form 8-K dated March 27, 1997, File No. 1-4955).

4.5		8.05% Junior Subordinated Deferrable Interest Debenture, Series 1997 of HECO (Exhibit 4(f) to HECO’s Current Report on Form 8-K dated March 27, 1997, File No. 1-4955).

4.6		Trust Guarantee Agreement with respect to HECO Trust I dated as of March 1, 1997 (Exhibit 4(g) to HECO’s Current Report on Form 8-K dated March 27, 1997, File No. 1-4955).

4.7		MECO Junior Indenture with The Bank of New York, as Trustee, including HECO Subsidiary Guarantee, dated as of March 1, 1997 (with the form of MECO’s 8.05% Junior Subordinated Deferrable Interest Debenture, Series 1997 included as Exhibit A) (Exhibit 4(h)-1 to HECO’s Current Report on Form 8-K dated March 27, 1997, File No. 1-4955).

4.8		HELCO Junior Indenture with The Bank of New York, as Trustee, including HECO Subsidiary Guarantee, dated as of March 1, 1997 (with the form of HELCO’s 8.05% Junior Subordinated Deferrable Interest Debenture, Series 1997 included as Exhibit A) (Exhibit 4(h)-2 to HECO’s Current Report on Form 8-K dated March 27, 1997, File No. 1-4955).

4.9		Agreement as to Expenses and Liabilities among HECO Trust I, HECO, MECO and HELCO (Exhibit 4(i) to HECO’s Current Report on Form 8-K dated March 27, 1997, File No. 1-4955).

4.10		Amended and Restated Trust Agreement of HECO Capital Trust II (HECO Trust II) dated as of December 1, 1998 (Exhibit 4(c) to HECO’s Current Report on Form 8-K dated December 4, 1998, File No. 1-4955).

4.11		HECO Junior Indenture with The Bank of New York, as Trustee, dated as of December 1, 1998 (with the form of HECO’s 7.30% Junior Subordinated Deferrable Interest Debenture, Series 1998, included as Exhibit A) (Exhibit 4(d) to HECO’s Current Report on Form 8-K dated December 4, 1998, File No. 1-4955).

4.12		7.30% Cumulative Quarterly Income Preferred Security (liquidation preference $25 per preferred security) of HECO Trust II (Exhibit 4(e) to HECO’s Current Report on Form 8-K dated December 4, 1998, File No. 1-4955).

4.13		Trust Guarantee Agreement with respect to HECO Trust II dated as of December 1, 1998 (Exhibit 4(g) to HECO’s Current Report on Form 8-K dated December 4, 1998, File No. 1-4955).


Exhibit no.		Description

4.14		MECO Junior Indenture with The Bank of New York, as Trustee, including HECO Subsidiary Guarantee, dated as of December 1, 1998 (with the form of MECO’s 7.30% Junior Subordinated Deferrable Interest Debenture, Series 1998 included as Exhibit A) (Exhibit 4(h) to HECO’s Current Report on Form 8-K dated December 4, 1998, File No. 1-4955).

4.15		HELCO Junior Indenture with The Bank of New York, as Trustee, including HECO Subsidiary Guarantee, dated as of December 1, 1998 (with the form of HELCO’s 7.30% Junior Subordinated Deferrable Interest Debenture, Series 1998) (Substantially the same as the MECO Junior Indenture included as Exhibit 4.14).

4.16		Agreement as to Expenses and Liabilities among HECO Trust II, HECO, MECO and HELCO (Exhibit 4(i) to HECO’s Current Report on Form 8-K dated December 4, 1998, File No. 1-4955).

10.1(a)		Power Purchase Agreement between Kalaeloa Partners, L.P., and HECO dated October 14, 1988 (Exhibit 10(a) to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1988, File No. 1-4955).

10.1(b)		Amendment No. 1 to Power Purchase Agreement between HECO and Kalaeloa Partners, L.P., dated June 15, 1989 (Exhibit 10(c) to HECO’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1989, File No. 1-4955).

10.1(c)		Lease Agreement between Kalaeloa Partners, L.P., as Lessor, and HECO, as Lessee, dated February 27, 1989 (Exhibit 10(d) to HECO’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1989, File No. 1-4955).

10.1(d)		Restated and Amended Amendment No. 2 to Power Purchase Agreement between HECO and Kalaeloa Partners, L.P., dated February 9, 1990 (Exhibit 10.2(c) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989, File No. 1-4955).

10.1(e)		Amendment No. 3 to Power Purchase Agreement between HECO and Kalaeloa Partners, L.P., dated December 10, 1991 (Exhibit 10.2(e) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1991, File No. 1-4955).

10.1(f)		Amendment No. 4 to Power Purchase Agreement between HECO and Kalaeloa Partners, L.P., dated October 1, 1999 (Exhibit 10.1 to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2000, File No. 1-4955).

10.2(a)		Power Purchase Agreement between AES Barbers Point, Inc. and HECO, entered into on March 25, 1988 (Exhibit 10(a) to HECO’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1988, File No. 1-4955).

10.2(b)		Agreement between HECO and AES Barbers Point, Inc., pursuant to letters dated May 10, 1988 and April 20, 1988 (Exhibit 10.4 to HECO’s Annual Report on Form 10-K for fiscal year ended December 31, 1988, File No. 1-4955).

10.2(c)		Amendment No. 1, entered into as of August 28, 1988, to Power Purchase Agreement between AES Barbers Point, Inc. and HECO (Exhibit 10 to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1989, File No. 1-4955).


Exhibit no.		Description

10.2(d)		HECO’s Conditional Notice of Acceptance to AES Barbers Point, Inc. dated January 15, 1990 (Exhibit 10.3(c) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989, File No. 1-4955).

*10.2(e)		Amendment No. 2, entered into as of May 8, 2003, to Power Purchase Agreement between AES Hawaii, Inc. and HECO.

10.3(a)		Amended and Restated Power Purchase Agreement between Hilo Coast Processing Company and HELCO dated March 24, 1995 (Exhibit 10 to HECO’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1995, File No. 1-4955).

10.3(b)		Second Amended and Restated Power Purchase Agreement between Hilo Coast Power Company and HELCO dated October 4, 1999 (Exhibit 10 to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1999, File No. 1-4955).

10.3(c)		Amendment No. 1 to the Second Amended and Restated Power Purchase Agreement between Hilo Coast Power Company and HELCO dated November 5, 1999 (Exhibit 10.3(b) to HECO’s Annual Report on Form 10-K for fiscal year ended December 31, 2001, File No. 1-4955).

10.4(a)		Agreement between MECO and Hawaiian Commercial & Sugar Company pursuant to letters dated November 29, 1988 and November 1, 1988 (Exhibit 10.8 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1988, File No. 1-4955).

10.4(b)		Amended and Restated Power Purchase Agreement by and between A&B-Hawaii, Inc., through its division, Hawaiian Commercial & Sugar Company, and MECO, dated November 30, 1989 (Exhibit 10(e) to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1990, File No. 1-4955).

10.4(c)		First Amendment to Amended and Restated Power Purchase Agreement by and between A&B-Hawaii, Inc., through its division, Hawaiian Commercial & Sugar Company, and MECO, dated November 1, 1990, amending the Amended and Restated Power Purchase Agreement dated November 30, 1989 (Exhibit 10(f) to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1990, File No. 1-4955).

10.4(d)		Letter agreement dated December 11, 1997 to Extend Term of Amended and Restated Power Purchase Agreement Between A&B-Hawaii, Inc., through its division, Hawaiian Commercial & Sugar Company, and MECO dated November 30, 1989, as Amended on November 1, 1990 (Exhibit 10.4(c) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.4(e)		Letter agreement dated October 22, 1998 to Extend Term of Amended and Restated Power Purchase Agreement Between A&B-Hawaii, Inc., through its division, Hawaiian Commercial & Sugar Company, and MECO dated November 30, 1989, as Amended on November 1, 1990 (Exhibit 10.4(d) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1998, File No. 1-4955).


Exhibit no.		Description

10.4(f)		Termination Notice dated December 27, 1999 for Amended and Restated Power Purchase Agreement by and between A&B Hawaii, Inc., through its division, Hawaiian Commercial & Sugar Company, and MECO, dated November 30, 1989, as amended (Exhibit 10.2 to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2000, File No. 1-4955).

10.4(g)		Rescission dated January 23, 2001 of Termination Notice for Amended and Restated Power Purchase Agreement by and between A&B Hawaii, Inc., through its division, Hawaiian Commercial & Sugar Company, and MECO, dated November 30, 1989, as amended (Exhibit 10.4(f) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 1-4955).

10.5(a)		Purchase Power Contract between HELCO and Thermal Power Company dated March 24, 1986 (Exhibit 10(a) to HECO’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1989, File No. 1-4955).

10.5(b)		Firm Capacity Amendment between HELCO and Puna Geothermal Venture (assignee of AMOR VIII, who is the assignee of Thermal Power Company) dated July 28, 1989 to Purchase Power Contract between HELCO and Thermal Power Company dated March 24, 1986 (Exhibit 10(b) to HECO’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1989, File No. 1-4955).

10.5(c)		Amendment made in October 1993 to Purchase Power Contract between HELCO and Puna Geothermal Venture dated March 24, 1986, as amended (Exhibit 10.5(b) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.5(d)		Third Amendment dated March 7, 1995 to the Purchase Power Contract between HELCO and Puna Geothermal Venture dated March 24, 1986, as amended (Exhibit 10.5(c) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.5(e)		Performance Agreement and Fourth Amendment dated February 12, 1996 to the Purchase Power Contract between HELCO and Puna Geothermal Venture dated March 24, 1986, as amended (Exhibit 10.5(b) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1995, File No. 1-4955).

10.6(a)		Purchase Power Contract between HECO and the City and County of Honolulu dated March 10, 1986 (Exhibit 10.9 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989, File No. 1-4955).

10.6(b)		Amendment No. 1 to Purchase Power Contract between HECO and the City and County of Honolulu dated March 10, 1986 (Exhibit 10.6 (a) to HECO’s Annual Report on Form 10-K for fiscal year ended December 31, 2001, File No. 1-4955).

10.6(c)		Firm Capacity Amendment, dated April 8, 1991, to Purchase Power Contract, dated March 10, 1986, by and between HECO and the City & County of Honolulu (Exhibit 10 to HECO’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1991, File No. 1-4955).

10.6(d)		Amendment No. 2 to Purchase Power Contract Between HECO and City and County of Honolulu dated March 10, 1986 (Exhibit 10.6(c) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).


Exhibit no.		Description

10.7(a)		Power Purchase Agreement between Encogen Hawaii, L.P. and HELCO dated October 22, 1997 (but with the following attachments omitted: Attachment C, “Selected portions of the North American Electric Reliability Council Generating Availability Data System Data Reporting Instructions dated October 1996” and Attachment E, “Form of the Interconnection Agreement between Encogen Hawaii, L.P. and HELCO,” which is provided in final form as Exhibit 10.7(a)) (Exhibit 10.7 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.7(b)		Power Purchase Agreement between Encogen Hawaii, L.P. and HELCO dated October 22, 1997 (Exhibit 10.7(a) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.7(c)		Amendment No. 1, executed on January 14, 1999, to Power Purchase Agreement between Encogen Hawaii, L.P. and HELCO dated October 22, 1997 (Exhibit 10.7(b) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1998, File No. 1-4955).

10.7(d)		Power Purchase Agreement Novation dated November 8, 1999 by and among Encogen Hawaii, L.P., Hamakua Energy Partners and HELCO (Exhibit 10.7(c) to HECO’s Annual Report on Form 10-K for fiscal year ended December 31, 2001, File No. 1-4955).

10.7(e)		Guarantee Agreement dated November 8, 1999 between TECO Energy, Inc. and HELCO (Exhibit 10.7(d) to HECO’s Annual Report on Form 10-K for fiscal year ended December 31, 2001, File No. 1-4955).

10.8		Low Sulfur Fuel Oil Supply Contract by and between Chevron and HECO dated as of November 14, 1997 (confidential treatment has been requested for portions of this exhibit) (Exhibit 10.8 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.9		Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract by and between Chevron and HECO, MECO, HELCO, HTB and YB dated as of November 14, 1997 (confidential treatment has been requested for portions of this exhibit) (Exhibit 10.9 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.10		Facilities and Operating Contract by and between Chevron and HECO dated as of November 14, 1997 (confidential treatment has been requested for portions of this exhibit) (Exhibit 10.10 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.11		Low Sulfur Fuel Oil Supply Contract by and between BHP Petroleum Americas Refining Inc. and HECO dated as of November 14, 1997 (confidential treatment has been requested for portions of this exhibit) (Exhibit 10.11 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.12		Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract by and between BHP Petroleum Americas Refining Inc. and HECO, MECO and HELCO dated November 14, 1997 (confidential treatment has been requested for portions of this exhibit) (Exhibit 10.12 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).


Exhibit no.		Description

10.13		Contract of private carriage by and between HITI and HELCO dated December 4, 2000 (Exhibit 10.13 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 1-4955).

10.14		Contract of private carriage by and between HITI and MECO dated December 4, 2000 (Exhibit 10.14 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 1-4955).

10.15		HECO Nonemployee Directors’ Deferred Compensation Plan (Exhibit 10.16 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1990, File No. 1-4955).

10.16		HEI and HECO Executives’ Deferred Compensation Agreement. The agreement pertains to and is substantially identical for all the HEI and HECO executive officers (Exhibit 10.15 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1991, File No. 1-8503).

11		Computation of Earnings Per Share of Common Stock. See note on HECO’s Selected Financial Data on page 49 herein.

*12		Computation of Ratio of Earnings to Fixed Charges. Filed herein as page 108.

18		KPMG LLP letter re: change in accounting principle (Exhibit 18.2 to HECO’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 1-4955).

*21		Subsidiaries of HECO. Filed herein as page 109.

*23.2		Accountants’ Consent. Filed herein as page 103.

*31.3		Certification Pursuant to 13a-14 of the Securities and Exchange Act of 1934, as Adopted by Section 302 of the Sarbanes-Oxley Act of 2002 of T. Michael May (HECO Chief Executive Officer). Filed herein as page 110.

*31.4		Certification Pursuant to 13a-14 of the Securities and Exchange Act of 1934, as Adopted by Section 302 of the Sarbanes-Oxley Act of 2002 of Richard von Gnechten (HECO Chief Financial Officer). Filed herein as page 111.

*32.3		Written Statement Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002 of T. Michael May, HECO Chief Executive Officer. Filed herein as page 112.

*32.4		Written Statement Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002 of Richard von Gnechten, HECO Chief Financial Officer. Filed herein as page 113.

*99.3		Reconciliation of electric utility operating income per HEI and HECO Consolidated Statements of Income. Filed herein as page 114.

99.4		HECO’s Consolidated Financial Statements (HECO Exhibit 99 to HECO’s Current Report on Form 8-K dated February 26, 2004, File No. 1-4955)

HEI Exhibit 11

Hawaiian Electric Industries, Inc.

COMPUTATION OF EARNINGS PER SHARE

OF COMMON STOCK

Years ended December 31, 2003, 2002, 2001, 2000 and 1999


(in thousands, except per share amounts)	2003			2002		2001			2000			1999
Net income (loss)
Continuing operations	$	118,048		$	118,217	$	107,746		$	109,336		$	96,426
Discontinued operations		(3,870	)		—		(24,041	)		(63,592	)		421

	$	114,178		$	118,217	$	83,705		$	45,744		$	96,847

Weighted-average number of common shares outstanding		37,348			36,278		33,754			32,545			32,188

Adjusted weighted-average number of common shares outstanding		37,487			36,477		33,942			32,687			32,291

Basic earnings (loss) per common share
Continuing operations	$	3.16		$	3.26	$	3.19		$	3.36		$	3.00
Discontinued operations		(0.10	)		—		(0.71	)		(1.95	)		0.01

	$	3.06		$	3.26	$	2.48		$	1.41		$	3.01

Diluted earnings (loss) per common share
Continuing operations	$	3.15		$	3.24	$	3.18		$	3.35		$	2.99
Discontinued operations		(0.10	)		—		(0.71	)		(1.95	)		0.01

	$	3.05		$	3.24	$	2.47		$	1.40		$	3.00

HEI Exhibit 12 (page 1 of 2)

Hawaiian Electric Industries, Inc.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES


	2003						2002						2001
Years ended December 31	⁽¹⁾			⁽²⁾			⁽¹⁾			⁽²⁾			⁽¹⁾			⁽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 (page 2 of 2)

Hawaiian Electric Industries, Inc.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

Continued


	2000						1999
Years ended December 31	⁽¹⁾			⁽²⁾			⁽¹⁾			⁽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.

100

HEI Exhibit 21

Hawaiian Electric Industries, Inc.

SUBSIDIARIES OF THE REGISTRANT

The following is a list of all direct and indirect subsidiaries of the registrant as of March 1, 2004. The state/place of incorporation or organization is noted in parentheses and subsidiaries of intermediate parent companies are designated by indentations.

Hawaiian

Electric Company, Inc. (Hawaii)

Maui Electric Company, Limited (Hawaii)

Hawaii Electric Light Company, Inc. (Hawaii)

HECO Capital Trust I (Delaware)

HECO Capital Trust II (Delaware)

HECO Capital Trust III (Delaware)

Renewable Hawaii, Inc. (Hawaii)

HEI Diversified, Inc. (Hawaii)

American Savings Bank, F.S.B. (federally chartered)

American Savings Investment Services Corp. (Hawaii)

Bishop Insurance Agency of Hawaii, Inc. (Hawaii)

AdCommunications, Inc. (Hawaii)

ASB Realty Corporation (Hawaii)

Pacific

Energy Conservation Services, Inc. (Hawaii)

HEI Properties, Inc. (Hawaii)

Hycap

Management, Inc. (Delaware)

HEI Preferred Funding, LP (a limited partnership in which Hycap Management, Inc. is the sole general partner) (Delaware)

Hawaiian Electric Industries Capital Trust I (a statutory trust) (Delaware)

Hawaiian Electric Industries Capital Trust II (a statutory trust) (Delaware) (potential financing entity)

Hawaiian Electric Industries Capital Trust III (a statutory trust) (Delaware) (potential financing entity)

The Old Oahu Tug Service, Inc. (Hawaii)

Discontinued operations:

HEI Power Corp. (Hawaii)

HEI Power Corp. International (Cayman Islands)

HEI Power Corp. Philippines (Cayman Islands)

HEI Power Corp. China (Republic of Mauritius)

HEI Power Corp. China II (Republic of Mauritius)

United Power Pacific Company Limited (Republic of Mauritius)

Baotou Tianjiao Power Co., Ltd. (People’s Republic of China)

(75% owned by United Power Pacific Company Limited)

HEI Investments, Inc. (Hawaii) (activity of leverage leases included in continuing operations)

Malama Pacific Corp. (Hawaii)

101

HEI Exhibit 23.1

[KPMG LLP letterhead]

Independent Auditors’ Consent

The Board of Directors

Hawaiian Electric Industries, Inc.:

We consent to incorporation by reference in Registration Statement Nos. 333-18809, 333-56312, 333-87782, 333-108110 and 333-113120 on Form S-3 and Registration Statement Nos. 33-65234, 333-05667, 333-02103 and 333-105404 on Form S-8 of Hawaiian Electric Industries, Inc., and Registration Statement Nos. 333-18809-01 and 333-18809-04 on Form S-3 of Hawaiian Electric Industries Capital Trust I and HEI Preferred Funding, LP and Registration Statement Nos. 333-18809-02 and 333-113120-02 on Form S-3 of Hawaiian Electric Industries Capital Trust II and Registration Statement Nos. 333-18809-03 and 333-113120-01 on Form S-3 of Hawaiian Electric Industries Capital Trust III of our report dated February 11, 2004, relating to the consolidated balance sheets of Hawaiian Electric Industries, Inc. and subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of income, changes in stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2003, which report is incorporated by reference in the 2003 annual report on Form 10-K/A of Hawaiian Electric Industries, Inc. We also consent to incorporation by reference of our report dated February 11, 2004 relating to the financial statement schedules of Hawaiian Electric Industries, Inc. in the aforementioned 2003 annual report on Form 10-K/A, which report is included in said Form 10-K/A.

Our reports refer to a change to the accounting method for goodwill and other intangible assets and for stock-based compensation.

/s/ KPMG LLP

Honolulu, Hawaii

March 9, 2004

102

HECO Exhibit 23.2

[KPMG LLP letterhead]

Independent Auditors’ Consent

The Board of Directors

Hawaiian Electric Company, Inc.:

We consent to incorporation by reference in Registration Statement Nos. 333-111073, 333-111073-01, 333-111073-02 and 333-111073-03 on Form S-3 of Hawaiian Electric Company, Inc., Hawaii Electric Light Company, Inc., Maui Electric Company, Limited, and HECO Capital Trust III of our report dated February 11, 2004, relating to the consolidated balance sheets and consolidated statements of capitalization of Hawaiian Electric Company, Inc. and subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of income, retained earnings, and cash flows for each of the years in the three-year period ended December 31, 2003, which report is incorporated by reference in the 2003 annual report on Form 10-K/A of Hawaiian Electric Industries, Inc. We also consent to incorporation by reference of our report dated February 11, 2004 relating to the financial statement schedule of Hawaiian Electric Company, Inc. in the aforementioned 2003 annual report on Form 10-K/A, which report is included in said Form 10-K/A.

/s/ KPMG LLP

Honolulu, Hawaii

March 9, 2004

103

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-K/A for the year ended December 31, 2003 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: March 9, 2004

/s/ Robert F. Clarke

Robert F. Clarke

Chairman, President and Chief Executive Officer

104

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-K/A for the year ended December 31, 2003 of Hawaiian Electric Industries, Inc. (“registrant”);

(a)

(b)

(c)

(a)

(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: March 9, 2004

/s/ Eric K. Yeaman

Eric K. Yeaman

Financial Vice President, Treasurer and Chief Financial Officer

105

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 Annual Report of Hawaiian Electric Industries, Inc. (HEI) on Form 10-K/A for the year ended December 31, 2003 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 December 31, 2003 and results of operations for the year ended December 31, 2003 of HEI and its subsidiaries.

/s/ Robert F. Clarke

Robert F. Clarke

Chairman, President and Chief Executive Officer of HEI

Date: March 9, 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.

106

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 Annual Report of Hawaiian Electric Industries, Inc. (HEI) on Form 10-K/A for the year ended December 31, 2003 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 December 31, 2003 and results of operations for the year ended December 31, 2003 of HEI and its subsidiaries.

/s/ Eric K. Yeaman

Eric K. Yeaman

Financial Vice President, Treasurer and Chief Financial Officer of HEI

Date: March 9, 2004

107

HECO Exhibit 12

Hawaiian Electric Company, Inc.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES


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

108

HECO Exhibit 21

Hawaiian Electric Company, Inc.

SUBSIDIARIES OF THE REGISTRANT

The following is a list of all subsidiaries of the registrant as of March 1, 2004. The state/place of incorporation or organization is noted in parentheses.

Maui Electric Company, Limited (Hawaii)

Hawaii Electric Light Company, Inc. (Hawaii)

HECO Capital Trust I (a statutory trust) (Delaware)

HECO Capital Trust II (a statutory trust) (Delaware)

HECO Capital Trust III (a statutory trust) (Delaware)

Renewable Hawaii, Inc. (Hawaii)

109

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-K/A for the quarter ended December 31, 2003 of Hawaiian Electric Company, Inc. (“registrant”);

(a)

(b)

(c)

(a)

(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: March 9, 2004

/s/ T. Michael May

T. Michael May

President and Chief Executive Officer

110

HECO Exhibit 31.4

Certification Pursuant to Section 13a-14 of the Securities Exchange Act of 1934 of Richard A. von Gnechten

(HECO Chief Financial Officer)

I, Richard A. von Gnechten, certify that:

1. I have reviewed this report on Form 10-K/A for the year ended December 31, 2003 of Hawaiian Electric Company, Inc. (“registrant”);

(a)

(b)

(c)

(a)

(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: March 9, 2004

/s/ Richard A. von Gnechten

Richard A. von Gnechten

Financial Vice President

111

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 Annual Report of Hawaiian Electric Company, Inc. (HECO) on Form 10-K/A for the year ended December 31, 2003 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 December 31, 2003 and results of operations for the year ended December 31, 2003 of HECO and its subsidiaries.

/s/ T. Michael May

T. Michael May

President and Chief Executive Officer of HECO

Date: March 9, 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.

112

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 Annual Report of Hawaiian Electric Company, Inc. (HECO) on Form 10-K/A for the year ended December 31, 2003 as filed with the Securities and Exchange Commission (the HECO Report), I, Richard A. von Gnechten, 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 December 31, 2003 and results of operations for the year ended December 31, 2003 of HECO and its subsidiaries.

/s/ Richard A. von Gnechten

Richard A. von Gnechten

Financial Vice President

Date: March 9, 2004

113

HECO Exhibit 99.3

Hawaiian Electric Company, Inc.

RECONCILIATION OF ELECTRIC UTILITY OPERATING

INCOME PER HEI AND HECO CONSOLIDATED

STATEMENTS OF INCOME


Years ended December 31	2003			2002			2001
(in thousands)
Operating income from regulated and nonregulated activities before income taxes (per HEI Consolidated Statements of Income)	$	176,565		$	194,956		$	193,945

Deduct:
Income taxes on regulated activities		(50,175	)		(56,729	)		(55,434	)
Revenues from nonregulated activities		(3,647	)		(4,247	)		(4,992	)

Add:
Expenses from nonregulated activities		2,095			1,177			1,813

Operating income from regulated activities after income taxes (per HECO Consolidated Statements of Income)	$	124,838		$	135,157		$	135,332

114

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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 execution of this report by registrant Hawaiian Electric Company, Inc. shall be deemed to relate only to matters having reference to such registrant and its subsidiaries.


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

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

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

Date:	March 9, 2004	Date:	March 9, 2004

115