10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2002

OR

¨ 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) 900 Richards Street, Honolulu, Hawaii 96813 Telephone (808) 543-5662	99-0208097
1-4955	HAWAIIAN ELECTRIC COMPANY, INC. (A Hawaii Corporation) 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 (QUIPSSM)	New York Stock Exchange
Hawaiian Electric Company, Inc.	Guarantee with respect to 7.30% Cumulative Quarterly Income Preferred Securities Series 1998 (QUIPSSM)	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.   ¨

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 nonaffiliates of the registrants on June 30, 2002	Number of shares of common stock outstanding of the registrants on March 10, 2003
Hawaiian Electric Industries, Inc.	$1,546,487,536.65	37,024,258 (Without par value)
Hawaiian Electric Company, Inc.	Not applicable	12,805,843 ($6  2/3 par value)

DOCUMENTS INCORPORATED BY REFERENCE

Document	Part of Form 10-K into which the document is incorporated
Annual Reports to Stockholder(s) of the following registrants for the fiscal year ended December 31, 2002:
Hawaiian Electric Industries, Inc.	Parts I, II, III and IV
Hawaiian Electric Company, Inc. (except for pages 3, 58 and 60)	Parts I, II, III and IV
Portions of Proxy Statement of Hawaiian Electric Industries, Inc., dated March 10, 2003, for the Annual Meeting of Stockholders	Part III

This combined Form 10-K 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.

TABLE OF CONTENTS

		Page
Glossary of Terms		ii
Forward-Looking Statements and Risk Factors		vi
PART I
Item 1.	Business	1
Item 2.	Properties	49
Item 3.	Legal Proceedings	50
Item 4.	Submission of Matters to a Vote of Security Holders	51
Executive Officers of the Registrant (Hawaiian Electric Industries, Inc.)		51
PART II
Item 5.	Market for Registrants’ Common Equity and Related Stockholder Matters	52
Item 6.	Selected Financial Data	54
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	54
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	54
Item 8.	Financial Statements and Supplementary Data	54
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	54
PART III
Item 10.	Directors and Executive Officers of the Registrants	55
Item 11.	Executive Compensation	58
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	61
Item 13.	Certain Relationships and Related Transactions	62
Item 14.	Controls and Procedures	63
PART IV
Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	64
Independent Auditors’ Report - Hawaiian Electric Industries, Inc.		66
Independent Auditors’ Report - Hawaiian Electric Company, Inc.		67
Index to Exhibits		72
Signatures		97
Certifications		100

i

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, AdCommunications, Inc., American Savings Mortgage Co., Inc. and ASB Realty Corporation
BIF	Bank Insurance Fund
BoA	Bank of America, FSB
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	Hawaiian Electric Industries, Inc. and its direct and indirect subsidiaries, including, without limitation, Hawaiian Electric Company, Inc., Maui Electric Company, Limited, Hawaii Electric Light Company, Inc., HECO Capital Trust I, HECO Capital Trust II, Renewable Hawaii, Inc., HEI Diversified, Inc., American Savings Bank, F.S.B. and its subsidiaries, Pacific Energy Conservation Services, Inc., HEI District Cooling, Inc., ProVision Technologies, Inc., HEI Properties, Inc., HEI Leasing, Inc., 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.
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
ERL	Environmental Response Law of the State of Hawaii
FDIC	Federal Deposit Insurance Corporation

ii

GLOSSARY OF TERMS (continued)

Terms	Definitions
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 and Renewable Hawaii, Inc.
HECO’s Annual Report	Portions of Hawaiian Electric Company, Inc.’s 2002 Annual Report to Stockholder filed as HECO Exhibit 13, which portions are incorporated into this Form 10-K by reference
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 by reference to pages 23 to 57 of HECO’s Annual Report
HECO’s MD&A	Hawaiian Electric Company, 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 by reference to pages 5 to 21 of HECO’s Annual Report
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., ProVision Technologies, Inc., HEI Properties, Inc., HEI Leasing, Inc., 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 2002 Annual Report to Stockholders, which is filed as HEI Exhibit 13 and incorporated into this Form 10-K 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 by reference to pages 37 to 78 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 by reference to pages 4 to 31 of HEI’s Annual Report
HEI’s 2003 Proxy Statement	Portions of Hawaiian Electric Industries, Inc.’s 2003 Proxy Statement dated March 10, 2003, which portions are incorporated into this Form 10-K 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 parent company of several subsidiaries. On October 23, 2001, the HEI Board of Directors adopted a formal plan to exit the international power business engaged in by HEI Power Corp. 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.
MSFO	Medium sulfur fuel oil
MW	Megawatts
na	Not applicable
NOV	Notice of Violation
OPA	Federal Oil Pollution Act of 1990
OTS	Office of Thrift Supervision, Department of Treasury
PCB	Polychlorinated biphenyls

iv

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
see	When used with reference to the HEI Annual Report, HECO Annual Report, HEI’s Consolidated Financial Statements, HEI’s MD&A, HEI’s Quantitative and Qualitative Disclosures about Market Risk, HECO’s Consolidated Financial Statements, HECO’s MD&A, HECO’s Quantitative and Qualitative Disclosures about Market Risk or HEI’s 2003 Proxy Statement, “see” means that the referenced information is incorporated by reference to those documents
SAIF	Savings Association Insurance Fund
SEC	Securities and Exchange Commission
SOP	Statement of Position
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. (HTB)), a wholly-owned subsidiary of Hawaiian Electric Industries, Inc. On November 10, 1999, HTB sold YB and substantially all of HTB’s operating assets and changed its name
UIC	Underground Injection Control
UST	Underground storage tank
YB	Young Brothers, Limited, which was sold on November 10, 1999, was formerly a wholly-owned subsidiary of Hawaiian Tug & Barge Corp.

v

Forward-Looking Statements and Risk Factors

This report and other presentations made by Hawaiian Electric Industries, Inc. (HEI) and Hawaiian Electric Company, Inc. (HECO) and their subsidiaries contain “forward-looking statements,” which include statements that are predictive in nature, depend upon or refer to future events or conditions, and usually include words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “predicts,” “estimates” or similar expressions. In addition, any statements concerning future financial performance (including future revenues, expenses, earnings or losses or growth rates), ongoing business strategies or prospects and possible future actions, which may be provided by management, are also forward-looking statements. Forward-looking statements are based on current expectations and projections about future events and are subject to risks, uncertainties and assumptions about HEI and its subsidiaries (including HECO and its subsidiaries), the performance of the industries in which they do business and economic and market factors, among other things. These forward-looking statements are not guarantees of future performance.

Risks, uncertainties and other important factors that could cause actual results to differ materially from those in forward-looking statements and from historical results include, but are not limited to, the following:

• the effects of international, national and local economic conditions, including the condition of the Hawaii tourist and construction industries and the Hawaii and continental U.S. housing markets;

• the effects of weather and natural disasters;

• the effects of terrorist acts, the war on terrorism, potential war with Iraq, potential conflict or crisis with North Korea and other global developments;

• 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;

• product demand 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 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, including changes in laws, rules and regulations applicable to HEI, HECO and their subsidiaries; 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); and changes in taxation;

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

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

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

• the results of financing efforts;

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

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

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

• the risks of suffering losses that are uninsured; and

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

Forward-looking statements speak only as of the date of the report, presentation or filing in which they are made.

vi

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. HECO also owns all the common securities of HECO Capital Trust I and HECO Capital Trust II (Delaware statutory business trusts), which were formed to effect the issuances of $50 million of 8.05% cumulative quarterly income preferred securities in March 1997 and $50 million of 7.30% cumulative quarterly income preferred securities in December 1998, 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.; HEI Properties, Inc. (HEIPI); HEI Leasing, Inc. (currently inactive); Hycap Management, Inc. and its subsidiary; Hawaiian Electric Industries Capital Trust I; Hawaiian Electric Industries Capital Trust II and III (at all times inactive entities); HEI District Cooling, Inc. (currently inactive); 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 and had 71 retail branches as of December 31, 2002. ASB has subsidiaries involved in the sale and distribution of investment and insurance products, advertising activities for ASB and its subsidiaries and holding real estate for employee use, 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. was formed in October 1998 to sell, install, operate and maintain on-site power generation equipment and auxiliary appliances in Hawaii and the Pacific Rim. HEI Leasing, Inc. was formed in February 2000 to own passive investments and real estate subject to leases, but is currently inactive. 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 business 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 is currently inactive.

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.

1

For information about the Company’s discontinued operations, see Note 13 to HEI’s Consolidated Financial Statements at pages 73 to 75 of HEI’s Annual Report.

For financial information about the Company’s industry segments, see Note 2 to HEI’s Consolidated Financial Statements at pages 50 to 51 of HEI’s Annual Report.

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 at pages 4 to 31, 31 to 36 and 37 to 78, respectively, of HEI’s Annual Report.

HEI’s website address is www.hei.com. HEI and HECO currently make available 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 2002, the electric utilities’ revenues amounted to approximately 76% of HEI’s consolidated revenues.

The islands of Oahu, Maui, Lanai, Molokai and Hawaii have a combined population currently estimated at 1,185,000, 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, incorporated herein by reference to pages 4 to 31, 31 to 36 and 37 to 78, respectively, of HEI’s Annual Report, and HECO’s MD&A, HECO’s “Quantitative and Qualitative Disclosures about Market Risk” and HECO’s Consolidated Financial Statements incorporated herein by reference to pages 5 to 21, 22 and 23 to 57, respectively, of HECO’s Annual Report.

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, 2002, 2001 and 2000 and electric sales revenues by company for each of the years then ended:

	2002			2001			2000
(dollars in thousands)	Customer accounts	Electric sales revenues		Customer accounts	Electric sales revenues		Customer accounts	Electric sales revenues
HECO	283,161	$	865,608	280,911	$	882,308	278,260	$	880,663
MECO	59,983		191,029	58,840		203,847	57,601		192,823
HELCO	66,411		191,589	65,241		193,209	63,778		192,174
	409,555	$	1,248,226	404,992	$	1,279,364	399,639	$	1,265,660

2

Revenues from the sale of electricity in 2002 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 derived approximately 9%, 10% and 10% of their operating revenues from the sale of electricity to various federal government agencies in 2002, 2001 and 2000, 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 will necessitate 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 anticipates 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. Under the GSA-BOA, HECO completed an air conditioning upgrade project and provided design work for solar water heating at a federal office building in downtown Honolulu in 1997 and 1998.

In 1996, HECO signed an umbrella Basic Ordering Agreement with the Department of Defense (DOD-BOA). In December 2001, a new DOD-BOA was signed under which HECO will perform energy audits, feasibility design studies and construction projects. Through 2002, completed projects included construction of an 1800-ton chiller plant at the Pearl Harbor Naval Shipyard, construction of a central chiller plant at Schofield Barracks, installation of solar water heating and retrofit lighting at three Naval housing facilities, the $10 million Pearl Harbor Naval Shipyard energy conservation project and a $2 million residential solar water heating project for the Army’s Helemano housing in central Oahu.

In 1997, HECO and the U.S. Postal Service (USPS) signed a Shared Energy Savings Contract. Under the Contract, HECO performed feasibility studies at 11 USPS sites on Oahu. A $3 million energy efficiency project at the USPS’ primary mail processing facility at the Honolulu International Airport was completed in 2001.

In 2001, HECO was awarded a $1 million contract to perform feasibility studies for most of the major buildings on the campus of the University of Hawaii at Manoa and at various Community Colleges throughout the State. The contract included energy efficiency assessments and electrical metering. This contract was completed in 2002.

Executive Order 13123 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 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.

3

Selected consolidated electric utility operating statistics

	2002		2001		2000		1999		1998
KWH sales (millions)
Residential		2,778.5		2,665.2		2,627.2		2,550.5		2,503.9
Commercial		3,073.6		3,016.1		2,923.5		2,781.5		2,674.9
Large light and power		3,639.2		3,636.5		3,666.9		3,598.3		3,636.4
Other		53.0		52.6		54.1		54.7		54.8
		9,544.3		9,370.4		9,271.7		8,985.0		8,870.0
KWH net generated and purchased (millions)
Net generated		6,249.7		6,042.4		6,247.0		6,115.1		5,958.0
Purchased		3,829.6		3,861.6		3,572.0		3,391.7		3,434.1
		10,079.3		9,904.0		9,819.0		9,506.8		9,392.1
Losses and system uses (%)		5.1		5.2		5.4		5.3		5.4
Energy supply (yearend)
Generating capability—MW		1,670		1,673		1,673		1,651		1,664
Firm purchased capability—MW		510		530		532		472		474
		2,180		2,203		2,205		2,123		2,138
Gross peak demand—MW 1		1,638		1,614		1,574		1,527		1,532
Btu per net KWH generated		10,673		10,675		10,818		10,789		10,684
Average fuel oil cost per Mbtu (cents)		466.4		539.3		538.5		329.7		308.8
Customer accounts (yearend)
Residential		356,244		352,132		347,316		342,957		338,454
Commercial		51,386		50,974		50,434		49,549		48,873
Large light and power		551		542		547		550		573
Other		1,374		1,344		1,342		1,299		1,289
		409,555		404,992		399,639		394,355		389,189
Electric revenues (thousands)
Residential	$	426,291	$	425,287	$	421,129	$	356,631	$	340,395
Commercial		425,595		436,751		422,977		345,808		322,772
Large light and power		389,312		409,977		414,067		336,434		331,957
Other		7,028		7,349		7,487		6,454		6,309
	$	1,248,226	$	1,279,364	$	1,265,660	$	1,045,327	$	1,001,433
Average revenue per KWH sold (cents)
Residential		15.34		15.96		16.03		13.98		13.60
Commercial		13.85		14.48		14.47		12.43		12.07
Large light and power		10.70		11.27		11.29		9.35		9.13
Other		13.26		13.98		13.84		11.80		11.52
Average revenue per KWH sold		13.08		13.65		13.65		11.63		11.29
Residential statistics
Average annual use per customer account (KWH)		7,840		7,620		7,618		7,490		7,425
Average annual revenue per customer account	$	1,203	$	1,216	$	1,221	$	1,047	$	1,009
Average number of customer accounts		354,419		349,782		344,882		340,528		337,218

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

4

Generation statistics

The following table contains certain generation statistics as of December 31, 2002 and for the year ended December 31, 2002. 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
Generating and firm purchased capability (MW) at December 31, 20021
Conventional oil-fired steam units	1,161.0		37.6		—		—		66.2		1,264.8
Diesel	—		96.1		10.4		9.8		39.0		155.3
Combustion turbines (peaking units)	102.0		—		—		—		—		102.0
Combustion turbines	—		42.4		—		2.2		45.3		89.9
Combined-cycle unit	—		58.0		—		—		—		58.0
Firm contract power 2	406.0		16.0		—		—		87.6		509.6
	1,669.0		250.1		10.4		12.0		238.1		2,179.6
Gross peak demand (MW)	1,250.0		193.9		4.9		6.6		182.2		1,637.6	3
Reserve margin	33.9	%	29.0	%	113.1	%	81.8	%	30.7	%	33.4	%
Annual load factor	73.5	%	71.1	%	69.1	%	68.7	%	69.8	%	72.8	%3
KWH net generated and purchased (millions)	7,757.7		1,166.9		28.6		38.5		1,087.6		10,079.3

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

² Nonutility generators (oil-fired except as noted)—HECO: 180 MW (Kalaeloa), 180 MW (AES Hawaii, coal-fired) and 46 MW (refuse-fired); MECO: 16 MW (HC&S, primarily bagasse-fired); HELCO: 5.6 MW (PGV, geothermal), 22 MW (HCPC, coal-fired) and 60 MW (Hamakua Partners).

³ Noncoincident and nonintegrated.

In 2002, a 1,500 KW hydroelectric unit owned by HELCO was damaged and HELCO is presently exploring options to rebuild or replace the unit.

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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. 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, subject to PUC approval, under which HECO’s three commercial and industrial DSM programs and two residential DSM programs would be continued until HECO’s next rate case, which, under the agreements, HECO committed to file using a 2003 or 2004 test year and following the PUC’s rules for determining the test year. 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, HELCO and MECO reached agreements with the Consumer Advocate and filed requests to continue their four existing DSM programs. See “Other regulatory matters—Demand-side management programs—agreements with the Consumer Advocate” at page 9 in HECO’s MD&A. All of the electric utilities’ existing DSM programs are energy efficiency programs designed to reduce the consumption of electricity.

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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. The Consumer Advocate has objected to the recovery of $1.9 million (before interest) of the $8.5 million of incremental IRP costs incurred during the 1995-1998 and 2001 period, and the PUC’s decision is pending on this matter. The Consumer Advocate has not yet filed its position on the recovery of the $1.5 million of integrated resource planning costs the electric utilities incurred from 1999 through 2000. Procedural schedules for the IRP cost proceedings have been established with respect to the 1999-2003 IRP costs.

The electric utilities have completed the recovery of their respective 1995 through 2000 incremental IRP costs through a surcharge on customer bills, subject to refund with interest.

In addition, HECO completed the recovery of its 2001 incremental IRP costs in June 2002, subject to refund with interest. MECO is scheduled to complete the recovery of its 2001 incremental IRP costs by August 2003. As of December 31, 2002, the amount of revenues the electric utilities recorded for IRP cost recoveries, subject to refund with interest, amounted to $16 million. HECO and MECO expect to begin recovering their incremental 2002 IRP costs, subject to refund with interest pending a final D&O, following the filing of actual 2002 costs (which is expected to occur in late March or early April 2003).

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 next 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. A second 107 MW simple-cycle combustion turbine is scheduled to be added in 2015, and in 2016 a conversion unit 105 MW steam turbine is scheduled to be added to create a dual-train combined-cycle unit. 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).

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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 Dispatchable Commercial and Industrial Load Program and a Residential Direct Load Control Program). HECO plans to file applications with the PUC requesting approval of these two load management programs by the second quarter of 2003.

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. MECO plans to work with the parties to the proceeding and attempt to reach a stipulation for PUC approval to expedite the proceeding, close the docket, and establish a schedule for MECO’s next IRP.

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 2004). 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 the second 20 MW increment 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 early 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. HELCO plans to work with the parties to the proceeding and, similar to HECO’s IRP, attempt to reach a stipulation for PUC approval to expedite the proceeding, close the docket, and establish a schedule for HELCO’s next IRP annual evaluation report and program implementation schedule and its next 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.

8

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, which were the first two phases of a planned 56 MW (net) DTCC unit, have been delayed. (See “HELCO power situation” in Note 11 of 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 HELCO now purchases 22 MW of firm capacity from HCPC’s coal-fired facility under a new PPA, as a result of the delays in adding new generation. HELCO also has deferred the retirements of some of its older generating units. If CT-4 and CT-5 are installed, this would extend the target date for the third phase of its DTCC unit or other firm capacity additions until sometime after 2012. The timing of the need for additional new generation may change, however, based on factors such as the availability of permitting for the Keahole installations, 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.

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). Under the amended PPA, AES Hawaii must obtain certain consents from HECO prior to entering into any arrangement to refinance the facility. HECO and AES Hawaii are in discussions regarding a possible refinancing of the facility by AES Hawaii, and concerning the terms upon which HECO would be willing to consent to the proposed refinancing. A letter of intent has been signed, but by its terms it is non-binding and the parties are proceeding to negotiate definitive documents. The arrangements addressed in the letter of intent contemplate that HECO will receive consideration for its consent, primarily in the form of a PPA amendment that will benefit ratepayers. If definitive documents acceptable to both parties are negotiated, they will be subject to several conditions, including PUC approval of the PPA amendment, and completion of the proposed refinancing.

9

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.

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 24% of HECO’s total generating and firm purchased capacity on the island of Oahu as of December 31, 2002. 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 power purchase agreements. As of December 31, 2002, MECO and HELCO had PPAs for 16 MW (includes 4 MW of system protection) and 88 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 in 2000, 2001 and 2002 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’ 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. With the completion of some maintenance activities and the easing of drought conditions, HC&S returned to full contract capacity of 16 MW in late October 2002. 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.

10

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 has been in decline since the middle of 2002 and PGV was able to produce only about 6 MW of firm capacity in 2002 compared to the 30 MW the company contracted to provide to HELCO. The loss of generation has been attributed to blockage of a source well due to a failed liner 5,000 feet below the earth’s surface and decreasing steam quality emanating from one of its 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 reached capacity levels of between 20 to 25 MW. PGV is in the process of obtaining a permit from the DOH for the new injection well. Without the new injection well, PGV is currently producing only about 10 to 11 MW due to the high brine content coming from the new source well. PGV is assessing whether to drill another source well or to install new generation equipment geared to utilize the excess brine. While PGV indicates it is seeking options to restore its 30 MW commitment to HELCO as soon as possible, HELCO cannot predict when PGV will reach its contractual commitment.

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. 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., 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 facility is designed to sell sufficient steam to be a QF. 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 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 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 has been limited to 55-57 MW in early 2003. Hamakua Partners has requested outages to correct the problems and HELCO has tentatively scheduled the outages for March and April 2003.

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. 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

11

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, but, final agreement has not been reached on various technical issues. Throughout 2002, the PUC has been kept informed through submittal of status of negotiations letters.

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 has not begun construction of its windfarm. GE Wind Energy completed the acquisition of certain assets of Enron Wind Corporation in May 2002, including the proposed KPP project. GE Wind Energy and Hawi Renewable Development Inc. (HRD) have since indicated they are in discussions to sell the windfarm project to HRD.

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 be limited to 3 MW, if the KPP windfarm is connected to the electric grid through the same 34.5 kV line. HELCO and HRD are in negotiations for a new PPA, under which HRD would sell energy from an expanded windfarm (approximately 10.6 MW) at the proposed windfarm site, if the KPP project is cancelled.

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 Tesoro Hawaii Corp. dba BHP Petroleum Americas Refining Inc. (Tesoro). These 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, MECO and HELCO executed joint fuel supply contracts with Chevron and 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.

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, 2003.

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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 2002, 2001 and 2000:

	HECO		MECO		HELCO		Consolidated
	$/Barrel	¢/MBtu	$/Barrel	¢/MBtu	$/Barrel	¢/MBtu	$/Barrel	¢/MBtu
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
2000	31.63	503.1	38.91	651.0	35.37	577.1	33.44	538.5

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 2002, over 99% of HECO’s generation fuel consumption consisted of LSFO. The balance of HECO’s fuel consumption was diesel. Diesel made up approximately 73% of MECO’s and 32% 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. 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’ price for MSFO averaged approximately 3% above the average price in 2001, while the price for LSFO and diesel averaged approximately 7% and 16%, respectively below 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 77% of the net energy generated and purchased by HECO and its subsidiaries in 2003 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.

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Transmission systems

HECO has 138 kilovolt (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 generating units located in West Oahu (1,057 MW); Waiau, adjacent to Pearl Harbor (499 MW); and Honolulu (113 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. See “Oahu transmission system” in HECO’s MD&A.

HELCO system. HELCO serves the island of Hawaii’s electricity requirements with firm capacity generating units located in West Hawaii (42 MW) and East Hawaii (196 MW). HELCO’s nonfirm power sources total 26 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 generating units located on the island of Maui (250 MW), Molokai (12 MW) and Lanai (10 MW). MECO has no nonfirm power sources. MECO transmits and distributes power to its service area on the islands of Maui, Molokai and Lanai through approximately 128 miles of 69 kv overhead lines and approximately 10 miles of 34.5 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

In July 2002, Commissioner Dennis R. Yamada retired and Commissioner Wayne H. Kimura became the Chairman of the PUC. In September 2002, Gregg J. Kinkley began serving as Commissioner for a term to expire in June 2004, subject to state Senate confirmation. Prior to his appointment, Mr. Kinkley served as the Consumer Advocate of the State of Hawaii Department of Commerce and Consumer Affairs. Continuing to serve is Commissioner Janet E. Kawelo.

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Most 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. purchased power) and the cost of plant and equipment, including the cost of new capital projects to maintain and improve service reliability. As of March 10, 2003, the return on rate base (RORB) found by the PUC to be reasonable in the most recent final rate decision for each utility was 9.16% for HECO (D&O issued on December 11, 1995, based on a 1995 test year), 9.14% for HELCO (D&O issued on February 8, 2001, based on a 2000 test year) and 8.83% for MECO (amended D&O issued on April 6, 1999, based on a 1999 test year). For 2002, the actual simple average RORBs (calculated under the rate-making method and reported to the PUC) for HECO, HELCO and MECO were 8.94%, 9.15% and 8.83%, respectively. In 2002, MECO’s revenues from shareholder incentives were $0.7 million lower than the amount that would have been recorded if MECO had not agreed to cap such incentives when its authorized return on rate base was exceeded. Also in 2002, HELCO slightly exceeded its authorized return on rate base. In 2002, HECO did not exceed its authorized return on rate base.

Hawaiian Electric Company, Inc.

In December 1993, HECO filed a request to increase rates based on a 1995 test year. HECO requested a 4.1% increase (as revised), or $28.2 million in annual revenues, based on a 13.25% return on average common equity (ROACE). In December 1995, HECO received a final D&O authorizing a 1.3%, or $9.1 million, increase in annual revenues, based on a 1995 test year and an 11.4% ROACE. HECO has not subsequently initiated a rate case, but in 2001 it agreed to initiate a rate case using a 2003 or 2004 test year. Also, see “Recent rate requests—Hawaiian Electric Company, Inc.” in HECO’s MD&A.

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 “Certain factors that may affect future results and financial condition–Other regulatory and permitting contingencies” in HECO’s MD&A and “HELCO power situation” in Note 11 of HECO’s 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 rest of the rate case. The rider provides the rates, terms and conditions for obtaining backup and supplemental electric power from the utility when a customer obtains all or part of its electric power from sources other than HELCO.

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% 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.

Regulatory asset related to Barbers Point Tank Farm project costs

See Note 6 to HECO’s Consolidated Financial Statements.

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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. Management cannot predict what changes, if any, may result from these efforts or what impact, if any, the changes may have on the Company’s or consolidated HECO’s financial condition, results of operations or liquidity.

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 clearly 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 important developments in 2002. EMF was formally classified as a possible human carcinogen in reports from two major public health organizations—the International Agency for Research on Cancer (IARC) and the California Department of Health Services (CDHS). The full implications of the IARC and CDHS reports remain to be seen. This does not mean that EMF has been established as a cause of childhood leukemia or any other cancer. The reports, however, may raise the profile of the EMF issue for electric utilities.

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.

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

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

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

The Complaint alleges that HECO’s payments to AES-HI for power, based on the prices, terms and conditions in the PUC-approved Amended PPA, have been “excessive” by over $1 billion since September 1992, and that approval of the Amended PPA was wrongfully obtained from the PUC as a result of alleged misrepresentations

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and/or material omissions by the defendants, individually and/or in conspiracy, with respect to the estimated future costs of the Amended PPA versus the costs of hypothetical HECO-owned units. The Complaint included four claims for relief or causes of action: (1) violations of Hawaii’s Unfair and Deceptive Practices Act, (2) unjust enrichment/restitution, (3) fraud and (4) violation of Hawaii’s False Claim Act, otherwise known as qui tam claims (asserting that the State declined to take over the action). The Complaint sought treble damages, attorneys’ fees, rescission of the Amended PPA and punitive damages against HECO, HEI, AES-HI and AES.

On May 22, 2002, AES, with the consent of HECO and HEI, removed the case to the U.S. District Court for the District of Hawaii (District Court) on the ground that the action arises under and is completely preempted by the Public Utility Regulatory Policies Act of 1978.

On June 12, 2002, HECO and HEI filed a motion to dismiss the complaint on the grounds that the plaintiffs’ claims either arose prior to enactment of the Hawaii False Claims Act, which does not have retroactive application, or are barred by the applicable statutes of limitations. AES also filed a motion to dismiss, on the same and additional grounds.

Plaintiffs moved to remand the case to state court on June 21, 2002. On November 14, 2002, the District Court Judge remanded the case back to state court and denied plaintiffs’ request for attorneys’ fees and costs.

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

As a result of the Circuit Court’s ruling, the only claim that appears to remain is under the Hawaii False Claims Act based on allegations that false bills or claims were submitted to the State after May 26, 2000. Under the False Claims Act, a defendant may be liable to a qui tam plaintiff for treble damages, plus civil penalties of a minimum of $5,000 for each false claim, plus attorneys’ fees and costs incurred in the action. The Plaintiffs appear to claim that each monthly bill submitted to each state agency and office on Oahu constitutes a separate false claim. In early 2003, AES filed a motion to dismiss the remaining claims under the Hawaii False Claims Act, on the grounds that: 1) PURPA precludes judicial review of the PUC decision that approved the AES contract; 2) plaintiffs failed to pursue and exhaust administrative remedies; and 3) PURPA preempts challenges to rates established by the PUC in approving the AES contract.

Management intends to vigorously defend the lawsuit.

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 not discussed herein, including (but not limited to) HELCO’s Keahole power situation and HECO’s Kamoku-Pukele transmission line.

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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, 2002, ASB was the third largest financial institution in the State of Hawaii with total assets of $6.3 billion and deposits of $3.8 billion. In 2002, the bank’s revenues amounted to approximately 24% of HEI’s consolidated revenues.

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, 2002, 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 (BoA) (see below). ASB is subject to OTS regulations on dividends and other distributions applicable to financial institutions regulated by the OTS.

Effective December 6, 1997, ASB acquired certain loans and other assets and assumed certain deposits and other liabilities of the Hawaii operations of BoA pursuant to a Purchase and Assumption Agreement executed on May 26, 1997, as amended. ASB used the purchase method of accounting to account for the transaction. In this transaction, ASB assumed liabilities with an estimated fair value of $1.7 billion and paid a $0.1 billion premium on certain transferred deposit liabilities. The estimated fair value of tangible and intangible assets acquired, including cash of $0.8 billion, amounted to $1.8 billion. ASB recorded the excess of the purchase price over the estimated fair value of the identifiable net assets acquired of $72 million as goodwill and recorded the core deposit premium of approximately $20 million as an intangible asset. 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 intangible assets” in Note 1 of 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.

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

	Years ended December 31,
	2002		2001		2000
Common equity to assets ratio
Average common equity divided by average total assets 1	7.20	%	6.65	%	6.22	%
Return on assets
Net income for common stock divided by average total assets 1, 2	0.92		0.81		0.68
Return on common equity
Net income for common stock divided by average common equity 1, 2	12.7		12.3		11.0
Tangible efficiency ratio
Total general and administrative expenses divided by net interest income and other income	58		56		57

¹ Average balances calculated using the average daily balances during 2002 and 2001 (except for return on common equity, which is calculated using the average month-end balance) and the average month-end balances during 2000.

² In 2001 and 2000, net income includes amortization of goodwill and other intangibles. In 2002, goodwill is no longer amortized, but other intangibles are still amortized, and goodwill and other intangibles are tested for impairment at least annually.

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 during 2002 and 2001 and the average month-end balances during 2000.

	Years ended December 31,
(in thousands)	2002		2001		2000
Assets
Investment securities	$	246,321	$	308,712	$	287,906
Mortgage-related securities		2,654,302		2,345,630		2,058,706
Loans receivable, net		2,844,341		2,963,521		3,215,879
Other		392,338		391,040		380,609
	$	6,137,302	$	6,008,903	$	5,943,100
Liabilities and stockholder’s equity
Savings deposits	$	2,394,435	$	2,059,486	$	2,007,787
Term certificates		1,323,118		1,578,650		1,529,525
Other borrowings		1,770,831		1,778,766		1,880,952
Other		132,223		117,366		80,262
Stockholder’s equity		516,695		474,635		444,574
	$	6,137,302	$	6,008,903	$	5,943,100

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 for 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. In 2001, mortgage-related securities increased and loans receivable decreased largely because ASB exchanged loans for $0.4 billion of mortgage-related securities. The decreases in the average balances of other borrowings were due to the payoff of maturing borrowings with funds from deposit inflows.

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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 in HEI’s Annual Report 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, 2002, 2001 and 2000.

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, 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
Year ended December 31, 2001 vs. 2000
Income from interest-earning assets
Loan portfolio	$	(2,867	)	$	(19,777	)	$	(22,644	)
Mortgage-related securities		(19,981	)		19,822			(159	)
Investments		(2,269	)		1,148			(1,121	)
		(25,117	)		1,193			(23,924	)
Expense from interest-bearing liabilities
Deposits		(6,041	)		3,380			(2,661	)
FHLB advances and other borrowings		(16,352	)		(6,277	)		(22,629	)
		(22,393	)		(2,897	)		(25,290	)
Net interest income	$	(2,724	)	$	4,090		$	1,366

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 $53.0 million in 2002, $45.0 million in 2001 and $27.3 million in 2000. The increase in other income for 2002 was due to increases in fee income from its debit and automated teller machines (ATM) cards resulting from ASB’s expansion of its debit card base and its introduction of new ATM services in 2001 as well as higher fee income from its deposit liabilities as a result of restructuring of deposit products. 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. The increase in other

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income for 2001 was primarily due to a $8.0 million gain on sale of investment and mortgage-related securities, increases in fees from ATM and debit cards resulting from ASB’s expansion of its debit card base and its introduction of new check cashing ATMs, increases in fee income from its deposit liabilities as a result of restructuring of deposit products, fee income from BIA which was acquired in March 2001 and increases in revenues from sales of annuity products from American Savings Investment Services Corp.

Lending activities

General. Loans and mortgage-related securities of $5.7 billion represented 90.6% of total assets at December 31, 2002, compared to $5.2 billion, or 86.7%, and $5.3 billion, or 88.5%, at December 31, 2001 and 2000, 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,
	2002					2001					2000
(dollars in thousands)	Balance			% of total		Balance			% of total		Balance			% of total
Real estate loans 1
Conventional (1-4 unit residential)	$	2,389,852		41.70	%	$	2,294,372		44.02	%	$	2,758,667		52.23	%
Commercial real estate		197,371		3.45			196,515		3.77			156,177		2.95
		2,587,223		45.15			2,490,887		47.79			2,914,844		55.18
Less
Deferred fees and discounts		(18,937	)	(0.33	)		(17,946	)	(0.34	)		(21,588	)	(0.41	)
Undisbursed loan funds		(21,412	)	(0.37	)		(22,910	)	(0.45	)		(17,559	)	(0.33	)
Allowance for loan losses		(23,708	)	(0.42	)		(26,085	)	(0.50	)		(24,800	)	(0.47	)
Total real estate loans, net		2,523,166		44.03			2,423,946		46.50			2,850,897		53.97
Other loans
Consumer and other loans		245,853		4.29			252,487		4.84			238,351		4.51
Commercial loans		247,114		4.31			197,333		3.79			134,784		2.55
		492,967		8.60			449,820		8.63			373,135		7.06
Less
Deferred fees and discounts		(416	)	—			—		—			—		—
Undisbursed loan funds		(1	)	—			(5	)	—			(58	)	—
Allowance for loan losses		(21,727	)	(0.38	)		(16,139	)	(0.31	)		(12,649	)	(0.24	)
Total other loans, net		470,823		8.22			433,676		8.32			360,428		6.82
Mortgage-related securities, net of discounts		2,736,679		47.75			2,354,849		45.18			2,070,827		39.21
Total loans and mortgage-related securities, net	$	5,730,668		100.00	%	$	5,212,471		100.00	%	$	5,282,152		100.00	%

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

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	December 31,
	1999					1998
(dollars in thousands)	Balance			% of total		Balance			% of total
Real estate loans 1
Conventional (1-4 unit residential)	$	2,769,101		53.40	%	$	2,689,682		54.51	%
Commercial real estate		170,663		3.29			198,530		4.03
		2,939,764		56.69			2,888,212		58.54
Less
Deferred fees and discounts		(24,083	)	(0.46	)		(21,229	)	(0.43	)
Undisbursed loan funds		(19,368	)	(0.37	)		(14,685	)	(0.30	)
Allowance for loan losses		(22,319	)	(0.43	)		(27,944	)	(0.57	)
Total real estate loans, net		2,873,994		55.43			2,824,354		57.24
Other loans
Consumer and other loans		244,933		4.72			253,232		5.13
Commercial loans		106,098		2.05			94,045		1.91
		351,031		6.77			347,277		7.04
Less
Deferred fees and discounts		—		—			(7	)	—
Undisbursed loan funds		(118	)	—			(16,592	)	(0.34	)
Allowance for loan losses		(13,029	)	(0.25	)		(11,835	)	(0.24	)
Total other loans, net		337,884		6.52			318,843		6.46
Mortgage-related securities, net of discounts		1,973,146		38.05			1,791,353		36.30
Total loans and mortgage-related securities, net	$	5,185,024		100.00	%	$	4,934,550		100.00	%

¹ Includes renegotiated loans.

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

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, loans originated by ASB are secured by real estate located in Hawaii. As of December 31, 2002, approximately $22.7 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 2002, 2001, 2000, 1999 and 1998 were $1.2 billion, $1.0 billion, $0.5 billion, $0.6 billion and $0.6 billion, respectively. The demand for loans is primarily dependent on the Hawaii real estate market and loan refinancing activity. The increase in loan originations during 2002 was due to the strong Hawaii real estate market and low interest rates which have resulted in increased affordability of housing for consumers and higher loan refinancings. The increase in loan originations during 2001 was primarily due to the low interest rate environment, which resulted in higher loan refinancings. The decrease in loans originated in 2000 from 1999 was due in part to a rise in interest rates and a slow Hawaii real estate market.

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.

23

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, 2002, 2001 and 2000, construction and development loans of $46.2 million, $52.0 million and $38.9 million which represented 1.5%, 1.8% and 1.2%, respectively, of ASB’s gross loan portfolio. Although construction and development loans are a small part of ASB’s current loan portfolio, in 2001 ASB enhanced its commercial real estate lending capabilities to diversify its loan portfolio and plans to increase construction and development lending. See “Loan portfolio risk elements.”

Multifamily residential and commercial real estate lending. Permanent loans secured by multifamily properties (generally apartment buildings), as well as commercial and industrial properties (including office buildings, shopping centers and warehouses), are originated by ASB for its own portfolio as well as for participation with other lenders. In 2002, 2001 and 2000, loan originations on these types of properties of $65.3 million, $55.0 million and $13.7 million, which accounted for approximately 7.6%, 8.3% and 4.2%, respectively, of ASB’s total mortgage loan originations. In 2001, ASB enhanced its commercial real estate lending capabilities and plans to increase commercial real estate lending in the future. The objective of commercial real estate lending is to diversify ASB’s loan portfolio.

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 2002, 2001 and 2000, gross loan originations of these types of $131.8 million, $191.5 million and $103.5 million, which accounted for approximately 10.8%, 18.3% and 19.1%, 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 designed to diversify ASB’s asset structure, shorten maturities, provide rate sensitivity to the loan portfolio and attract business checking deposits. As of December 31, 2002, 2001 and 2000, business loans represented 8.3%, 6.9% and 4.2%, 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” at page 11 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 “Loan origination and commitment fees” 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 0.19%, 0.24% and 0.15% of total assets at December 31, 2002, 2001 and 2000, respectively.

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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). 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 level of nonaccrual and renegotiated loans represented 0.9%, 1.5%, 1.5%, 2.3% and 3.1%, of ASB’s total net loans outstanding at December 31, 2002, 2001, 2000, 1999 and 1998, respectively. The following table sets forth certain information with respect to nonaccrual and renegotiated loans as of the dates indicated:

	December 31,
(in thousands)	2002			2001			2000			1999			1998
Nonaccrual loans—
Real estate
1-4 unit residential	$	9,783		$	22,495		$	26,738		$	43,750		$	47,565
Income property		983			10,129			15,132			18,747			29,456
Total real estate		10,766			32,624			41,870			62,497			77,021
Consumer		1,382			1,965			2,844			3,777			6,454
Commercial		3,633			3,018			2,872			2,192			2,030
Total nonaccrual loans	$	15,781		$	37,607		$	47,586		$	68,466		$	85,505
Nonaccrual loans to total loans		0.5	%		1.3	%		1.4	%		2.1	%		2.6	%
Renegotiated loans not included above—
Real estate
1-4 unit residential	$	—		$	—		$	48		$	876		$	1,705
Income property		7,582			3,874			—			5,154			10,559
Commercial		2,175			2,681			—			—			—
Total renegotiated loans	$	9,757		$	6,555		$	48		$	6,030		$	12,264

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 1998, the increase in nonaccrual loans was a result of Hawaii’s weak economy and was primarily due to a $10.3 million increase in nonaccruing, smaller balance residential loans. In 2000 and 1999, the $20.9 million and $17.0 million, respectively, 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.

A potential downturn in the Hawaii economy as a result of global issues could lead to higher delinquencies in ASB’s loan portfolio. At December 31, 2002, ASB had outstanding loans to businesses with significant exposure to the tourist industry, including an airline and hotels, of approximately 1.3% of total loans outstanding. Substantially all of these loans are secured by commercial real estate and/or business assets and were performing as of December 31, 2002.

25

Allowance for loan losses. ASB maintains an allowance for loan losses that it believes is adequate to absorb estimated losses on all loans. The level of allowance for loan losses is based on a continuing assessment of existing risks in the loan portfolio, historical loss experience, changes in collateral values, and current and anticipated economic conditions. For business and commercial real estate loans, a risk rating system is used. Loans are rated based on the degree of risk at origination and periodically thereafter, as appropriate. A credit review department performs an evaluation of these loan portfolios to ensure compliance with the internal risk rating system and timeliness of rating changes. Adverse changes in any of the risk factors could result in higher charge-offs and loan loss provisions. When loans are deemed impaired, the amount of impairment is measured based on the present value of expected future cash flows discounted at the loan’s effective interest rate and the fair value of the collateral securing the loan. ASB generally ceases the accrual of interest on loans when they become 90 days past due or when there is reasonable doubt as to collectibility. ASB uses either the cash or cost recovery method to record cash receipts on impaired loans that are not accruing interest. Impairment losses are charged to the provision for loan losses and included in the allowance for loan losses.

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

	Years ended December 31,
(dollars in thousands)	2002			2001			2000			1999			1998
Allowance for loan losses, beginning of year	$	42,224		$	37,449		$	35,348		$	39,779		$	29,950
Provision for loan losses		9,750			12,500			13,050			16,500			13,802
Charge-offs
Residential real estate loans		2,345			4,800			8,867			4,962			1,987
Commercial real estate loans		441			215			–			10,776			–
Consumer loans		3,479			3,595			3,801			4,712			2,052
Commercial loans		1,479			1,013			670			1,209			525
Total charge-offs		7,744			9,623			13,338			21,659			4,564
Recoveries
Residential real estate loans		858			1,212			1,926			448			438
Commercial real estate loans		52			342			214			75			–
Consumer loans		257			311			244			188			127
Commercial loans		38			33			5			17			26
Total recoveries		1,205			1,898			2,389			728			591
Allowance for loan losses, end of year	$	45,435		$	42,224		$	37,449		$	35,348		$	39,779
Ratio of allowance for loan losses, December 31, to average loans outstanding		1.60	%		1.42	%		1.16	%		1.11	%		1.29	%
Ratio of provision for loan losses during the year to average loans outstanding		0.34	%		0.42	%		0.41	%		0.52	%		0.45	%
Ratio of net charge-offs during the year to average loans outstanding		0.23	%		0.26	%		0.34	%		0.66	%		0.13	%

26

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,
	2002				2001				2000
(dollars in thousands)	Balance		% of total		Balance		% of total		Balance		% of total
Residential real estate	$	6,246	77.6	%	$	9,933	78.0	%	$	13,224	83.9	%
Commercial real estate		6,343	6.4			9,031	6.7			8,928	4.7
Consumer		8,489	8.0			8,538	8.6			7,609	7.3
Commercial		12,118	8.0			6,388	6.7			4,126	4.1
Unallocated		12,239	NA			8,334	NA			3,562	NA
	$	45,435	100.0	%	$	42,224	100.0	%	$	37,449	100.0	%

	December 31,
	1999				1998
(dollars in thousands)	Balance		% of total		Balance		% of total
Residential real estate	$	14,394	84.2	%	$	10,523	83.2	%
Commercial real estate		7,963	5.2			16,896	6.1
Consumer		9,850	7.4			9,623	7.8
Commercial		3,060	3.2			2,057	2.9
Unallocated		81	NA			680	NA
	$	35,348	100.0	%	$	39,779	100.0	%

NA Not applicable

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, 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. 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 has remained essentially the same during the year. 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. In 1999, ASB’s allowance for loan losses decreased by $4.4 million. In 1999, management disposed of nonperforming loans at a loss, which resulted in higher charge-offs in 1999 compared to 1998. ASB increased its allowance for loan losses by $9.8 million in 1998 to establish additional specific loss allowances and in response to a rising trend of delinquencies caused by Hawaii’s weak economy.

27

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 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, 2002, 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 2002, 2001 or 2000.

As of December 31, 2002 and 2001, ASB’s held-to-maturity investment portfolio consisted of $89.5 million and $84.2 million, respectively, of investment in FHLB stock. As of December 31, 2000, ASB’s held-to-maturity investment portfolio, excluding mortgage-related securities, consisted of a $78.7 million investment in FHLB stock and a $13.1 million investment in collateralized debt obligations. The weighted-average rate on investments during 2002, 2001 and 2000 was 6.19%, 7.28% and 5.62%, 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, 2002, 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
FHLMC, GNMA, FNMA	$	947		$	628		$	185		$	100		$	1,860
Private issue		509			308			40			20			877
	$	1,456		$	936		$	225		$	120		$	2,737
Weighted average yield		3.89	%		4.77	%		5.84	%		6.80	%		4.48	%

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

ASB’s investment in securities issued by Countrywide Financial and GMAC RFC, with a market value of $230 million and $124 million, respectively, exceeded 10% of the Company’s stockholder’s equity as of December 31, 2002.

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, 2002, ASB had mortgage-related securities issued by FHLMC, GNMA and FNMA valued at $1.8 billion and private-issue mortgage-related securities valued at $0.9 billion in its available-for-sale investment portfolio.

28

Disposition of certain debt securities. In June 2000, the OTS advised ASB that four trust certificates, in the original aggregate principal amount of $114 million, were impermissible investments under regulations applicable to federal savings banks. The OTS subsequently required ASB to dispose of the securities. In April 2001, ASB sold one of the trust certificates for an amount approximating the original purchase price. After PaineWebber Incorporated (the broker that sold the remaining three trust certificates to ASB) rejected ASB’s demand that the transactions be rescinded, ASB filed a lawsuit against PaineWebber Incorporated. ASB is seeking rescission or other remedies, including recovery of any losses ASB (directly and through its indemnification of HEI) may incur as a result of its purchase and ownership of these trust certificates. For additional details, see Note 4 to HEI’s Consolidated Financial Statements.

To bring ASB into compliance with the OTS direction, ASB directed the trustees to terminate the principal swap component of the three trust certificates. After terminating the swaps, the related equity notes were sold by the swap counterparty to HEI. ASB has agreed to indemnify HEI against losses related to these income notes, but the indemnity obligation is payable solely out of any recoveries achieved in the litigation against PaineWebber Incorporated. In 2002, PaineWebber Incorporated filed a counterclaim alleging misrepresentation and fraud among other allegations.

In January 2003, a hearing on several motions for partial summary judgment was held. The Court denied all motions, except for a ruling that PaineWebber did not owe a fiduciary duty to ASB with respect to two of the three transactions. The Company has filed a motion for reconsideration on this ruling. In early March 2003, several additional motions filed by each party to request partial summary judgment relating to various aspects of ASB’s affirmative claims were heard. The Court denied certain of the motions, ruling that summary judgment was not available because there were issues of fact requiring trial on several claims and defining some of the elements that ASB must establish at trial to prevail on those claims. However, the court did grant motions for partial summary judgment in favor of PaineWebber with respect to certain of its alleged misrepresentations and omissions. The trial remains scheduled to begin in July 2003. Additional discovery and pretrial motion work is anticipated prior to trial. The ultimate outcome of this litigation cannot be determined at this time.

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 2002 and 2001, ASB had average deposits of $3.7 billion and $3.6 billion, respectively. Net savings inflow in 2002, 2001 and 2000 was $121.2 million, $94.9 million and $93.0 million, respectively. In the three years ended December 31, 2002, ASB had no deposits placed by or through a broker.

29

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 during 2002 and 2001 and the average month-end balances during 2000.

	Years ended December 31,
	2002						2001
(dollars in thousands)	Average balance		% of total deposits		Weighted average rate %		Average balance		% of total deposits		Weighted average rate %
Passbook accounts	$	1,188,042	31.9	%	1.22	%	$	1,049,441	28.9	%	1.91	%
Negotiable order of withdrawal accounts		802,651	21.6		0.13			699,997	19.2		0.59
Money market accounts		403,742	10.9		1.51			310,048	8.5		2.40
Certificate accounts		1,323,118	35.6		3.92			1,578,650	43.4		5.38
Total deposits	$	3,717,553	100.0	%	1.98	%	$	3,638,136	100.0	%	3.20	%

	Year ended December 31, 2000
(dollars in thousands)	Average balance		% of total deposits		Weighted average rate %
Passbook accounts	$	1,058,763	29.9	%	2.00	%
Negotiable order of withdrawal accounts		642,074	18.2		0.85
Money market accounts		306,950	8.7		2.94
Certificate accounts		1,529,525	43.2		5.46
Total deposits	$	3,537,312	100.0	%	3.37	%

At December 31, 2002, ASB had $262 million in certificate accounts of $100,000 or more, maturing as follows:

(in thousands)	Amount
Three months or less	$	67,863
Greater than three months through six months		36,098
Greater than six months through twelve months		33,993
Greater than twelve months		124,323
	$	262,277

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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 BoA. 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, 2002 quarterly payment is zero and its assessment for funding FICO interest payments is 1.68 cents per $100 of SAIF and BIF deposits, on an annual basis, based on deposits as of September 30, 2002.

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, 2002, 2001 and 2000, advances from the FHLB amounted to $1.2 billion, $1.0 billion and $1.2 billion, respectively. The weighted-average rates on the advances from the FHLB outstanding at December 31, 2002, 2001 and 2000 were 5.10%, 5.41% and 6.67%, respectively. The maximum amount outstanding at any month-end during 2002, 2001 and 2000 was $1.2 billion, $1.2 billion and $1.3 billion, respectively. Advances from the FHLB averaged $1.1 billion, $1.2 billion and $1.3 billion during 2002, 2001 and 2000, respectively, and the approximate weighted-average rate on the advances was 5.29%, 5.98% and 6.55%, 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 “Securities sold under agreements to repurchase” to HEI’s Consolidated Financial Statements). At December 31, 2002, 2001 and 2000, the entire outstanding amounts under these agreements of $667 million (including accrued interest of $6.4 million), $683 million (including accrued interest of $4.9 million) and $597 million (including accrued interest of $5.5 million), respectively, were to purchase identical securities. The weighted-average rates on securities sold under agreements to repurchase outstanding at December 31, 2002, 2001 and 2000 were 3.17%, 2.81% and 6.32%, respectively. The maximum amount outstanding at any month-end during 2002, 2001 and 2000 was $751 million, $722 million and $657 million, respectively. Securities sold under agreements to repurchase averaged $663 million, $629 million and $625 million during 2002, 2001 and 2000, respectively, and the approximate weighted-average interest rate under those agreements was 3.11%, 4.50% and 5.98%, respectively.

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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)	2002			2001			2000
Advances from the FHLB	$	1,176,252		$	1,032,752		$	1,249,252
Securities sold under agreements to repurchase		667,247			683,180			596,504
Total borrowings	$	1,843,499		$	1,715,932		$	1,845,756
Weighted-average rate		4.40	%		4.37	%		6.56	%

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, 7 FDIC-insured banks and approximately 100 credit unions at December 31, 2002. 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 type 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 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.

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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.” Government officials estimate that this rule allowed credit unions to add approximately 15 million people to their membership rolls. 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.

In January 2000, 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). 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, 2002, HEIPI’s venture capital investments (in companies based in Hawaii and the U.S. mainland) amounted to $3.5 million.

HEI Leasing, Inc.

HEI Leasing, Inc. was formed in February 2000 to own passive investments and real estate subject to leases. It currently holds no investments or real estate subject to leases and is inactive.

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The Old Oahu Tug Service, Inc.

On November 10, 1999, HTB changed its name to TOOTS. Prior to that date, HTB was the parent of YB. In November 1999, HTB sold substantially all of its operating assets and the stock of YB and ceased operations. HTB and its wholly-owned subsidiary, YB, had been acquired by HEI in 1986. HTB had provided marine transportation services in Hawaii and the Pacific area, including charter tug and barge and harbor tug operations. YB, which is a regulated interisland cargo carrier, transports general freight and containerized cargo by barge on a regular schedule between all major ports in Hawaii.

Discontinued operations

For information concerning the Company’s discontinued international power operations conducted by HEIPC and its subsidiaries and its discontinued residential real estate development business 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. See Note 13 to HEI’s Consolidated Financial Statements. 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 and was included in HEI’s 2001 income tax return as an ordinary loss. In 2002, HEI had requested that the Internal Revenue Service (IRS) confirm that the treatment of this loss, as an ordinary loss, was proper. This request for determination by the IRS is still in process, but in March 2003, the IRS made a tentative finding that the loss was a capital loss. The Company is currently evaluating the assertions made by the IRS in support of its tentative finding. Under the early determination process, the Company has the opportunity to refute the IRS’ assertions. The Company may also maintain its tax filing position and argue the issue when the IRS examines the 2001 income tax return. If the Company’s tax position does not ultimately prevail, the effect would be the Company would have to pay additional federal and state income taxes of $35 million for the 2001 tax year. However, in this event, the Company would likely take various actions which it believes would allow it to realize capital gains sufficient to offset the capital loss and limit the adverse impact on HEI’s income statement to the reversal of all or a portion of state tax benefits taken ($5 million) and interest on the late tax payments.

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 it 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. HEI has 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

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HEI Power Corp. Guam (for the HEIPC Group’s Guam project). In 1998, HEI filed two Form U-57’s on behalf of Baotou Tianjiao Power Co., Ltd. (for the HEIPC Group’s China project) and on behalf of Cagayan Electric Power & Light Co., Inc. (for the HEIPC Group’s investment in that entity). 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. The failure of ASB to satisfy the QTL test could result in a need to divest ASB. ASB met the QTL test at all times during 2002.

On January 23, 2003, the OTS issued a notice and request for comments on proposed changes to the Thrift Financial Report (TFR), effective with the March 31, 2004 report, and stated its intention to propose amendments to Schedule CMR, Consolidated Maturity and Rate, at a later date. Generally speaking, the OTS-regulated thrifts must file a TFR quarterly in order to provide the OTS with specific information. The proposed changes in the TFR would require additional details in areas in which the OTS believes such details would be helpful to it, and also would eliminate some of the detailed information required under the current form which the OTS no longer finds to be useful. Two areas in which the OTS would require greater detail are (i) holding companies such as HEI and HEIDI and (ii) transactions with affiliates. In addition, the OTS is proposing that the deadlines by which the TFR and its associated Schedules must be filed should be shortened. ASB has not yet analyzed the additional costs of providing the more detailed information that would be required in the proposed changes to the TFR.

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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 52% of their total capitalization (including in capitalization the current maturities of long-term debt, but excluding short-term borrowings) as of December 31, 2002. As of December 31, 2002, HECO and its subsidiaries had net assets of $923 million, of which approximately $452 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

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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 OTS notice requirement. 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

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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. 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

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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, 2002, 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. 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. Although ASB has “know your customer” policies in place, it will not be able to assess the additional cost (if any) of complying with the new regulations until they are issued. 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, 2002, ASB was in compliance with all of the minimum standards with a core capital ratio of 6.7% (compared to a 4.0% requirement), a tangible capital ratio of 6.7% (compared to a 1.5% requirement) and total risk-based capital ratio of 14.7% (based on risk-based capital of $452.7 million, $206.7 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).

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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, 2002, 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.

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. 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.

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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.

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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 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, 2002, ASB’s unused FHLB borrowing capacity was approximately $1.0 billion. ASB utilizes growth in deposits, advances from 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, 2002, 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 in 1991 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 may affect 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, 2002, 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, 2002, 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

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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 2002, ASB was in compliance with the QTL test. As of December 31, 2002, 90.7% 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.

ASB, as a member of the FHLB of Seattle, is required to own shares of capital stock in the FHLB of Seattle in an amount equal to the greater of 1% of ASB’s aggregate unpaid residential loan principal at the beginning of each year, 0.3% of total assets or 5% of FHLB advances outstanding and any shares held by ASB in excess of its required minimum may be immediately redeemed by ASB. However, 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 new 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, 2002, ASB was required to own capital stock in the FHLB of Seattle in the amount of $65.4 million. ASB’s excess capital stock in the FHLB of Seattle was $24.1 million. In addition, stock in the FHLB of Seattle will be 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. ASB received a CRA rating of “outstanding” from the OTS in December 1997 and such rating was reaffirmed as of September 2002.

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.

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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.

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.

The DOH conducted NPDES permit compliance inspections at HELCO’s Shipman generating station in February 2002, MECO’s Kahului generating station in July 2002, and at HECO’s Honolulu generating station in July 2002 and Kahe and Waiau generating stations in December 2002. All facilities were found to be in compliance with NPDES permit requirements.

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. On October 3, 2002, the Third Circuit Court reversed an earlier Decision and Order by the BLNR regarding construction of CT-4 and CT-5 and HELCO halted construction activity. Although the DOH indicated it was ready to issue the UIC permit, HELCO submitted a letter on November 20, 2002 to notify the DOH of the recently issued court order. The issuance of the permit is currently on hold. Regardless of the pending court decision on CT-4 and CT-5, HELCO intends to at least reactivate the UIC permit and complete the piping connections for existing wastewater operations at the facility. Existing wastewater management activities do not currently require a UIC permit, but will be rerouted to the injection wells as a process improvement. See Note 11 to HECO’s Consolidated Financial Statements.

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 have certain environmental obligations arising from conditions existing prior to the sale of YB, including obligations with respect to the Honolulu Harbor investigation. 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

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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, the EPA amended the revised regulations, which now require development of the SPCC plans for these facilities by April 17, 2003, and implementation of the plans by October 18, 2003. Concurrently, EPA proposed a rule to further extend compliance dates for the amended regulations by one year. 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 is affected by the 1990 Amendments to the Clean Air Act (CAA), recent changes to the National Ambient Air Quality Standard (NAAQS) for ozone, and adoption of a NAAQS for fine particulate matter. New and proposed 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, 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. 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 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, the DOH issued two NOVs to HELCO for earlier periods of non-complying emissions from CT-2 that HELCO and the DOH settled. Unit CT-2 is currently operating within all existing permit limits by virtue of its having passed its annual source tests since 1997.

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.

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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.

The DOH conducted solid and hazardous waste compliance inspections under RCRA at HELCO’s Hill generating station (including the Kanoelehua base yard) and Puna generating station in April 2000. The DOH issued inspection reports and warning letters to HELCO for the Hill/Kanoelehua facility and the Puna facility in June and July 2000, respectively. HELCO addressed the potential deficiencies at the Hill/Kanoelehua facility and submitted a response to the DOH in July 2000. The DOH issued a return to compliance letter for this facility in late July 2000. HELCO submitted its responses to the DOH’s Puna facility’s warning letter in September and December 2000. In January 2002, the DOH issued a second warning letter regarding a regulatory interpretation issue related to used oil processing at Puna. Based on follow-up discussions with the DOH, HELCO submitted a used oil processing permit application in March 2002 to bring closure to the used oil processing issue. In July 2002, the DOH issued a used oil processing permit to HELCO for the Puna facility. No enforcement action is anticipated.

The EPA conducted RCRA compliance inspections at the Kahului and Maalaea generating stations in June 2001. The Kahului facility is currently considered to be in compliance with RCRA requirements. In August 2001, the EPA issued a Warning Letter to MECO for potential RCRA deficiencies at the Maalaea facility, all of which have been addressed by MECO. MECO submitted its response to the warning letter and additional requested data to the EPA in September 2001. In August 2002, the EPA issued a Certification of Violation Correction letter that stated all potential violations listed in the Warning Letter were adequately addressed and that MECO had returned to compliance.

In July 1999, the DOH conducted a UST inspection at HECO’s Ward Avenue Complex. The DOH conducted another follow-up UST inspection at the Ward Avenue Complex in January 2002. The facility was found to be in compliance with UST requirements in both inspections. During 2002, the DOH also conducted UST inspections at MECO’s Puunana communications facility (April 2002) and Kahului baseyard (August 2002), HELCO’s Kona and Waimea baseyards (June 2002), and HECO’s Waiau (September 2002) and Kahe (November 2002) generating stations. While minor concerns were raised at the Kona, Waimea and Kahului baseyards, all concerns were addressed and all facilities are in compliance with UST requirements.

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 deviations in previous TRI reports. The Company is in the process of submitting corrected reports.

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 instituted procedures to monitor compliance with these regulations. In addition, HECO and its subsidiaries 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. All HECO, MECO and HELCO facilities are currently believed to be in compliance with PCB regulations.

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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 approximately 11,000 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. The interception trench appears to be operating 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, individually and in the aggregate, 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.

47

Securities ratings

As of March 10, 2003, the Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HEI’s and HECO’s securities were as follows:

	S&P	Moody’s
HEI
Commercial paper	A-2	P-2
Medium-term notes	BBB	Baa2
HEI-obligated preferred securities of trust subsidiary	BB+	Ba1
HECO
Commercial paper	A-2	P-2
Revenue bonds (insured)	AAA	Aaa
Revenue bonds (noninsured)	BBB+	Baa1
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. 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.

See “Liquidity and capital resources” in HEI’s MD&A.

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 several series of these revenue bonds are insured either by MBIA Insurance Corporation or by Ambac Assurance Corporation, 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 $2.8 million, $2.6 million and $3.0 million in 2002, 2001 and 2000, respectively, for research and development. Contributions to the Electric Power Research Institute accounted for most 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, 2002 and 2001, the Company had 3,220 and 3,189 full-time employees, respectively, of which 44 and 47 were employees of HEI, respectively, and 1,272 and 1,200 were employees of ASB and its subsidiaries, respectively.

HECO

At December 31, 2002, HECO and its subsidiaries had 1,894 full-time employees, compared with 1,930 at December 31, 2001. In August 2000, certain electric utility employees ratified new collective bargaining agreements covering approximately 62% of the employees of HECO, HELCO and MECO. The collective bargaining agreements

48

(including benefit agreements) cover a three-year period from November 1, 2000 through October 31, 2003 and expire at midnight on October 31, 2003. The electric utilities expect to begin negotiations for new collective bargaining agreements in the third quarter of 2003. See “Collective bargaining agreements” in HECO’s MD&A.

Other

The employees of HEI and its direct and indirect subsidiaries, other than the electric utilities, are not covered by any collective bargaining agreement.

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 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. 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 generating capability of 1,263 MW at December 31, 2002. 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 and 138,000 volts. The total capacity of HECO’s transmission and distribution substations was 6,617,500 kilovoltamperes at December 31, 2002.

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.

MECO owns and operates two generating plants on the island of Maui, at Kahului and Maalaea, with an aggregate generating capability of 234.1 MW as of December 31, 2002. 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 4,000 gallon fuel storage tank located in Hana. MECO owns 65.7 acres of undeveloped land at Waena.

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

49

MECO also owns and operates smaller distribution systems, generation systems (with an aggregate capability of 22.4 MW as of December 31, 2002) and fuel storage facilities on the islands of Lanai and Molokai, primarily on land owned by MECO.

HELCO owns and operates five generating plants on the island of Hawaii. These plants at Hilo (2), Waimea, Kona and Puna have an aggregate generating capability of 150.5 MW as of December 31, 2002 (excluding two small run-of-river hydro units 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.

Bank

ASB owns its executive office building in downtown Honolulu and land and an operations center in the Mililani Technology Park on Oahu. ASB also leases space in an executive office building in downtown Honolulu.

The following table sets forth information with respect to bank branches owned and leased by ASB at December 31, 2002.

	Number of branches
	Owned	Leased	Total
Oahu	10	39	49
Maui	3	5	8
Kauai	3	3	6
Hawaii	2	5	7
Molokai	—	1	1
	18	53	71

At December 31, 2002, the net book value of branches and office facilities is approximately $41 million. Of this amount, $35 million represents the net book value of the land and improvements for the branches and office facilities owned by ASB and $6 million represents the net book value of ASB’s leasehold improvements. The leases expire on various dates from April 2003 through April 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.

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ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

HEI and HECO:

During the fourth quarter of 2002, 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 12, 2003 and their years of company service are given as of December 31, 2002. Officers are appointed to serve until the meeting of the HEI Board of Directors after the next Annual Meeting of Stockholders (which will occur on April 22, 2003) 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 60
Chairman of the Board, President and Chief Executive Officer President and Chief Executive Officer Director (Company service: 15 years)	9/98 to date 1/91 to 8/98 4/89 to date
Eric K. Yeaman, age 35
Financial Vice President, Treasurer and Chief Financial Officer (Company service: none) 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).	01/03 to date
Peter C. Lewis, age 68
Vice President – Administration and Corporate Secretary Vice President – Administration (Company service: 34 years)	1/99 to date 10/89 to 12/98
Charles F. Wall, age 63
Vice President and Corporate Information Officer (Company service: 12 years)	7/90 to date
Andrew I. T. Chang, age 63
Vice President – Government Relations (Company service: 17 years)	4/91 to date

51

HEI Executive Officers	Business experience for past five years
(continued)
Curtis Y. Harada, age 47
Controller (Company service: 13 years)	1/91 to date
T. Michael May, age 56
President and Chief Executive Officer, Hawaiian Electric Company, Inc. Director, Hawaiian Electric Industries, Inc. Senior Vice President, Hawaiian Electric Industries, Inc. (Company service: 10 years)	9/95 to date 9/95 to date 9/95 to 4/01
Constance H. Lau, age 50
President and Chief Executive Officer, American Savings Bank, F.S.B. Director, Hawaiian Electric Industries, Inc Senior Executive Vice President and Chief Operating Officer, American Savings Bank, F.S.B. Treasurer, Hawaiian Electric Industries, Inc. (Company service: 18 years)	6/01 to date 6/01 to date 12/99 to 6/01 4/89 to 10/99

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 arrangement or understanding between any executive officer and any person pursuant to which the officer 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, 73 (Note 11, “Regulatory restrictions on net assets”) and 77 to 78 (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 March 10, 2003, was 14,459.

In 2002, HEI issued an aggregate of 8,500 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.

In 2001 and 2000, HEI issued an aggregate of 62,325 and 78,820 shares of unregistered common stock, respectively, pursuant to the HEI 1999 Nonemployee Company Director Stock Grant Plan (the HEI 1999 Nonemployee Director Plan), the HEI 1990 Nonemployee Director Stock Plan, amended effective April 27, 1999 (the Subsidiary Director Plan) and the Team Incentive Plan. Under the HEI 1999 Nonemployee Director Plan, each HEI nonemployee director received an annual stock grant of 300 shares of HEI common stock. Under the

52

Subsidiary Director Plan, 60% of the annual retainer payable to nonemployee subsidiary directors was paid in HEI common stock. Under the Team Incentive Plan, eligible employees of HECO, MECO and HELCO received awards of HEI common stock based on the attainment of performance goals by their respective companies. In early 2001, the Team Incentive Plan was terminated. Effective May 1, 2002, the provisions of the HEI 1999 Nonemployee Director Plan and the Subsidiary Director Plan were restated as the HEI Nonemployee Director Plan.

HEI did not register the shares issued under the director stock plans 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. HEI did not register the shares issued under the Team Incentive Plan because their initial sales to HECO, MECO and HELCO were exempt as transactions not involving any public offering under Section 4(2) of the Securities Act of 1933, as amended, and because their subsequent award to eligible employees did not involve a “sale,” as defined in Section 2(3) of the Securities Act of 1933, as amended. Awards of HEI common stock under the Team Incentive Plan were made to eligible employees on the basis of their attainment of performance goals established by their respective companies and no cash or other tangible or definable consideration was paid by such employees to their respective companies for the shares.

Equity compensation plan information

The following table sets forth information as of December 31, 2002 about HEI common stock that may be issued upon the exercise of awards granted under all of the Company’s equity compensation plans.

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	731,451	$	36.62	541,978

(1) This represents the number of shares under options outstanding as of December 31, 2002 and dividend equivalent shares accrued as of December 31, 2002 under such options.

(2) This represents the number of shares remaining available as of December 31, 2002, including 498,739 under the 1987 Stock Option and Incentive Plan and 43,239 under the HEI Nonemployee Director Plan.

NA Not applicable

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 2002 and 2001 were as follows:

Quarters ended	2002		2001
March 31	$	9,233,000	$	—
June 30		10,180,000		—
September 30		11,925,000		17,037,000
December 31		12,805,000		19,272,000

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The discussion of regulatory restrictions on distributions is incorporated herein by reference to page 47 (Note 12 to HECO’s Consolidated Financial Statements, “Regulatory restrictions on distributions to parent”) of HECO’s Annual Report.

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:

The information required by this item is incorporated herein by reference to page 4 of HECO’s Annual Report.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

HEI:

The information required by this item is incorporated herein by reference to pages 4 to 31 of HEI’s Annual Report.

HECO:

The information required by this item is incorporated herein by reference to pages 5 to 21 of HECO’s Annual Report.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

HEI:

The information required by this item is incorporated herein by reference to pages 31 to 36 of HEI’s Annual Report.

HECO:

The information required by this item is incorporated herein by reference to page 22 of HECO’s Annual Report.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

HEI:

The information required by this item is incorporated herein by reference to pages 37 to 78 of HEI’s Annual Report.

HECO:

The information required by this item is incorporated herein by reference to pages 23 to 57 of HECO’s Annual Report.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

HEI and HECO:

None

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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 51 and 52 of this report. The list of current directors of HEI is incorporated herein by reference to page 79 of HEI’s Annual Report. Information on the current directors’ business experience and directorships is incorporated herein by reference to pages 13 to 15 of HEI’s 2003 Proxy Statement. Information on the remuneration of HEI Directors is incorporated herein by reference to pages 17 to 18 of HEI’s 2003 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.

Section 16(a) beneficial ownership reporting compliance

For information required to be reported under this caption, see page 21 of HEI’s 2003 Proxy Statement.

HECO:

The following persons are, or may be deemed to be, executive officers of HECO. Their ages are given as of February 12, 2003 and their years of company service are given as of December 31, 2002. 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 2003) 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 60
Chairman of the Board	1/91 to date
(Company service: 15 years)
T. Michael May, age 56
President, Chief Executive Officer and Director	9/95 to date
Chairman of the Board, MECO and HELCO	9/95 to date
(Company service: 10 years)
Robert A. Alm, age 51
Senior Vice President – Public Affairs	7/01 to date
(Company service: 1 year)
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 and Senior Vice President of Financial Management Group at First Hawaiian Bank from 2/96 to 12/98.
Thomas L. Joaquin, age 59
Senior Vice President – Operations	7/01 to date
Vice President – Power Supply	7/95 to 06/01
(Company service: 29 years)

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HECO Executive Officers	Business experience for past five years
(continued)
Karl E. Stahlkopf, age 62
Senior Vice President – Energy Solutions and Chief Technology Officer	5/02 to date
(Company service: 8 months)
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 59
Vice President – Government & Community Affairs	5/01 to date
President, Maui Electric Company, Inc	9/96 to 5/01
(Company service: 17 years)
Jackie Mahi Erickson, age 62
Vice President & General Counsel	3/03 to date
Vice President – Customer Operations & General Counsel	10/98 to 3/03
Vice President – General Counsel & Government Relations	9/95 to 9/98
(Company service: 21 years)
Charles M. Freedman, age 56
Vice President – Corporate Relations	3/98 to date
Vice President – Corporate Excellence	7/95 to 2/98
(Company service: 11 years)
Chris M. Shirai, age 55
Vice President – Energy Delivery	12/99 to date
Manager, Engineering Department	7/96 to 11/99
(Company service: 33 years)
Thomas C. Simmons, age 54
Vice President – Power Supply	2/02 to date
Manager, Power Supply	7/95 to 2/02
(Company service: 31 years)
Richard A. von Gnechten, age 39
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: 11 years)

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HECO Executive Officers	Business experience for past five years
(continued)
Patricia U. Wong, age 46
Vice President – Corporate Excellence	3/98 to date
Manager, Environmental Department	10/96 to 2/98
(Company service: 12 years)
Lorie Ann K. Nagata, age 44
Treasurer	12/00 to date
Manager, Management Accounting	5/98 to date
Assistant Treasurer	3/97 to 11/00
Director, Management Accounting	12/94 to 4/98
(Company service: 20 years)
Ernest T. Shiraki, age 55
Controller	5/89 to date
(Company service: 33 years)
Molly M. Egged, age 52
Secretary	10/89 to date
(Company service: 22 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, T. Michael May and Molly M. Egged are also officers of one or more of the affiliated nonutility HEI companies.

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 director and any person pursuant to which the director was selected.

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 Board of Directors

The list of current directors of HECO is incorporated herein by reference to page 59 of HECO’s Annual Report. Information on the business experience and directorships of HECO directors who are also directors of HEI is incorporated herein by reference to pages 13 to 15 of HEI’s 2003 Proxy Statement.

Anne M. Takabuki and Barry K. Taniguchi, ages 46 and 55, as of February 12, 2003, respectively, are the only nonemployee directors of HECO who are not directors of HEI. Ms. Takabuki was elected a director of HECO in April 1997 and is Vice President/Secretary and General Counsel of Wailea Golf Resort, Inc. She also serves on the boards of Wailea Golf Resort, Inc. and its affiliated companies, MAGBA, Inc. and Kapiolani Medical Foundation and is a member of the advisory Board of Directors of MECO. Mr. Taniguchi was elected a director of HECO in April 2001 and is President of KTA Super Stores. He also serves on the boards of ASB, Puna Plantation Hawaii, Limited, and K. Taniguchi, Ltd. and is a member of the advisory Board of Directors of HELCO.

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Committees of the HECO Board

During 2002, 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 2002, the Audit Committee held five 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 financial statements which are included in HECO’s 2001 Annual Report to Stockholder.

Attendance at meetings

In 2002, 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 Committee on which they served.

ITEM 11. EXECUTIVE COMPENSATION

HEI:

The information required under this item for HEI is incorporated by reference to pages 17 to 19 and 22 to 34 of HEI’s 2003 Proxy Statement.

HECO:

Remuneration of HECO Directors

In 2002, Anne M. Takabuki and Barry K. Taniguchi were the only nonemployee HECO directors who were not also directors of HEI. Commencing May 1, 2002, 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. The Chairman of the HECO Audit Committee was paid an additional annual cash retainer of $3,000. Employee members of the Board of Directors are not compensated for attendance at any meeting of the Board or Committees of the Board.

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 2002. All compensation amounts presented for T. Michael May are the same amounts presented in HEI’s 2003 Proxy Statement.

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SUMMARY COMPENSATION TABLE

		Annual Compensation
					Awards		Payouts
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	2002	472,000	286,960	0	NA	25,000	150,645	7,314
President and Chief Executive Officer	2001	415,000	163,257	0	NA	20,000	54,540	18,881
	2000	408,000	62,971	0	NA	20,000	0	17,117
Robert A. Alm (7)	2002	223,000	57,227	0	NA	0	NA	1,698
Senior Vice President-Public Affairs	2001	100,000	30,367	0	NA	0	NA	2,825
Thomas L. Joaquin	2002	223,000	49,385	0	NA	0	NA	4,475
Senior Vice President-Operations	2001	202,000	58,597	0	NA	3,000	NA	11,745
	2000	189,000	39,880	0	NA	0	NA	10,126
Karl C. Stahlkopf (8)	2002	187,000	52,421	100,000	140,880	0	NA	4,929
Senior Vice President- Energy Solutions and Chief Technology Officer
Jackie Mahi Erickson	2002	187,000	38,869	0	NA	0	NA	4,929
Vice President & General Counsel	2001	181,000	47,844	0	NA	3,000	NA	13,503
	2000	175,000	44,803	0	NA	0	NA	12,012

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.

(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 at $46.96 per share. 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. As of December 31, 2002, the restricted stock value was $131,940 based on closing price of $43.98 per share on the New York Stock Exchange.

(4) Options granted earn dividend equivalents as further described below under “Option grants in last fiscal year.”

(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 accrued 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 “Other Compensation Plans” on page 33 of HEI’s 2003 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.

59

Option grants in last fiscal year

A stock option was granted in 2002 to only one of the HECO Named Executive Officers, Mr. May. Additional information required under this item is incorporated by reference on page 23 of HEI’s 2003 Proxy Statement.

Aggregated option exercises and fiscal yearend option values

The following table shows the stock options, including dividend equivalents, exercised by the HECO Named Executive Officers in 2002. 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 2002. HEI, under the Stock Option and Incentive Plan, 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

	Shares Acquired	Dividend Equivalents	Value Realized	Value Realized On Dividend	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	On Exercise (#)	Acquired On Exercise (#)	On Options ($)	Equivalents ($)	Exercisable/ Unexercisable (#)	Exercisable/ Unexercisable ($)
T. Michael May	37,000	11,399	239,053	496,156	36,721 / 61,024	612,421 /590,164
Robert A. Alm	—	—	—	—	—  /—	—  /—
Thomas L. Joaquin	—	—	—	—	10,679 / 3,460	161,189 /44,930
Karl C. Stahlkopf	—	—	—	—	—  /—	—  /—
Jackie Mahi Erickson	8,000	1,530	75,370	70,960	—   /3,460	—   /44,930

(1) Values based on closing price of $43.98 per share on the New York Stock Exchange on December 31, 2002.

Long-Term Incentive Plan awards table

A Long-Term Incentive Plan award made to Mr. May in 2002 was the only such award made to the HECO Named Executive Officers. Additional information required under this item is incorporated by reference to “Long-Term Incentive Plan (LTIP) Awards” on pages 24 to 26 of HEI’s 2003 Proxy Statement.

60

Pension plan

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 “Pension Plans” on pages 26 to 28 of HEI’s 2003 Proxy Statement.

The Retirement Plan provides a monthly retirement pension for life. Additional information required under this item is incorporated by reference to “Pension Plans” on pages 26 to 28 of HEI’s 2003 Proxy Statement. As of December 31, 2002, the HECO Named Executive Officers had the following number of years of credited service under the Retirement Plan: Mr. May, 10 years; Mr. Alm, 1 year; Ms. Erickson, 21 years; Mr. Joaquin, 29 years; and Mr. Stahlkopf, 8 months.

Change-in-Control Agreements

HECO does not have any 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 “Change-in-Control Agreements” on pages 28 to 29 of HEI’s 2003 Proxy Statement.

Executive Management Compensation

The HEI Compensation Committee, composed of six independent nonemployee directors, 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 pages 18 to 19 and 29 to 33 of HEI’s 2003 Proxy Statement. Actions of the 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 AND RELATED STOCKHOLDER MATTERS

HEI:

The information required under this item is incorporated by reference to page 20 of HEI’s 2003 Proxy Statement and “Market for Registrant’s Common Equity and Related Stockholder Matters–equity compensation plan information.”

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.

61

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 26, 2003, 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	2,492	—	—	—	2,492
Barry K. Taniguchi	—	1,618	—	—	1,618
Other HECO Named Executive Officers
Robert A. Alm	1,159	—	—	—	1,159
Thomas L. Joaquin	6,145	1,511	32	10,738	18,426
Karl C. Stahlkopf	3,151	—	—	—	3,151
Jackie Mahi Erickson	4,724	1,227	2	—	5,953
All directors and executive officers as a group (21 persons)	72,030	9,861	3,154	149,005	234,050	*

* HECO directors Clarke, Daniel, May, Plotts, Scott and Watanabe, who also serve on the HEI Board of Directors, are not shown separately, 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 page 20 of HEI’s 2003 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 12, 2003, 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 pages 37 and 38 of HEI’s 2003 Proxy Statement.

HECO:

Certain information required under this item is incorporated by reference to page 37 of HEI’s 2003 Proxy Statement. In addition, Karl C. Stahlkopf is currently 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 is interest free, with the unpaid principal balance due on May 22, 2003 or sooner if Mr. Stahlkopf ceases to be an employee of HECO.

62

ITEM 14. 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 March 13, 2003. Based on their evaluations, as of March 13, 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) are effective. There have been no significant changes in HEI’s internal controls or in other factors that could significantly affect these controls subsequent to March 13, 2003, including any corrective actions with regard to significant deficiencies and material weaknesses.

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 March 13, 2003. Based on their evaluations, as of March 13, 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) are effective. There have been no significant changes in HECO’s internal controls or in other factors that could significantly affect these controls subsequent to March 13, 2003, including any corrective actions with regard to significant deficiencies and material weaknesses.

63

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a)(1) Financial statements

The following financial statements contained in HEI’s Annual Report and HECO’s Annual Report are incorporated by reference in Part II, Item 8, of this Form 10-K:

	Pages in HEI’s and HECO’s Annual Report
	HEI	HECO
Independent Auditors’ Report	37	23
Consolidated Statements of Income, Years ended December 31, 2002, 2001 and 2000	38	24
Consolidated Statements of Retained Earnings, Years ended December 31, 2002, 2001 and 2000	NA	24
Consolidated Balance Sheets, December 31, 2002 and 2001	39	25
Consolidated Statements of Capitalization, December 31, 2002 and 2001	NA	26-27
Consolidated Statements of Changes in Stockholders’ Equity, Years ended December 31, 2002, 2001 and 2000	40	NA
Consolidated Statements of Cash Flows, Years ended December 31, 2002, 2001 and 2000	41	28
Notes to Consolidated Financial Statements	42-78	29-57

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:

		Page/s in Form 10-K
		HEI	HECO
Independent Auditors’ Report		66	67
Schedule I	Condensed Financial Information of Registrant, Hawaiian Electric Industries, Inc. (Parent Company) as of December 31, 2002 and 2001 and Years ended December 31, 2002, 2001 and 2000	68-70	NA
Schedule II	Valuation and Qualifying Accounts, Years ended December 31, 2002, 2001 and 2000	71	71

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 Annual Report and HECO’s Annual Report, which financial statements are incorporated herein by reference.

64

(a)(3) Exhibits

Exhibits for HEI and HECO and their subsidiaries are listed in the “Index to Exhibits” found on pages 72 through 83 of this Form 10-K. 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, 2002, HEI and/or HECO filed Current Reports, Forms 8-K, with the SEC as follows:

Dated (filing date)	Registrant/s	Items reported
October 3, 2002 (October 10, 2002)	HEI/HECO	Item 5. Update of HELCO Power Situation
October 21, 2002 (October 22, 2002)	HEI/HECO	Item 5. HEI’s October 21, 2002 news release (HEI reports third quarter 2002 earnings)
November 12, 2002 (November 12, 2002)	HEI/HECO	Item 5. HEI’s November 12, 2002 news release (HEI to webcast and teleconference financial analyst presentation on Tuesday, November 19, 2002)
November 13, 2002 (November 13, 2002)	HEI	Item 5. Announcement of the retirement of HEI Chief Financial Officer
December 17, 2002 (December 18, 2002)	HEI/HECO	Item 5. HEI and HECO announce appointment of Shirley J. Daniel, PH.D. to their Boards of Directors
December 26, 2002 (December 26, 2002)	HEI	Item 5. HEI’s December 26, 2002 news release (HEI announces appointment of Eric K. Yeaman as Financial Vice President, Treasurer and Chief Financial Officer)
January 14, 2003 (January 14, 2003)	HEI/HECO	Item 5. HEI’s January 14, 2003 news release (HEI to webcast and teleconference 2002 yearend earnings on January 21, 2003)
January 20, 2003 (January 21, 2003)	HEI/HECO	Item 5. HEI’s January 20, 2003 news release (HEI reports 2002 yearend earnings) and retirement benefits information
February 25, 2003 (February 26, 2003)	HEI/HECO	Item 7. Listing and attaching as exhibits HEI’s 2002 Annual Report to Stockholders in its entirety, portions of HECO’s 2002 Annual Report to Stockholder and Section 906 certifications
March 7, 2003 (March 10, 2003)	HEI	Item 5. Announcing HEI’s sale of $100 million of its Medium-Term Notes, Series D, and Item 7. Listing and attaching as exhibits notes, attorneys’ opinions and pricing supplements

65

[KPMG LLP letterhead]

Independent Auditors’ Report

The Board of Directors and Stockholders

Hawaiian Electric Industries, Inc.:

Under date of January 20, 2003, we reported on the consolidated balance sheets of Hawaiian Electric Industries, Inc. and subsidiaries as of December 31, 2002 and 2001, 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, 2002, as contained in the 2002 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 for the year 2002. 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

January 20, 2003

66

[KPMG LLP letterhead]

Independent Auditors’ Report

The Board of Directors and Stockholder

Hawaiian Electric Company, Inc.:

Under date of January 20, 2003, 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, 2002 and 2001, 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, 2002, as contained in the 2002 annual report to stockholder. These consolidated financial statements and our report thereon are incorporated by reference in the Company’s annual report on Form 10-K for the year 2002. 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

January 20, 2003

67

Hawaiian Electric Industries, Inc.

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)

CONDENSED BALANCE SHEETS

	December 31,
(in thousands)	2002		2001
Assets
Cash and equivalents	$	25,059	$	19,155
Advances to and notes receivable from subsidiaries		5,600		48,297
Available-for-sale investment securities		7,971		15,610
Accounts receivable		1,593		1,832
Property, plant and equipment, net		2,089		2,600
Deferred income tax assets		13,110		10,337
Other assets		4,152		5,530
Net assets of discontinued operations		787		—
Investments in subsidiaries, at equity		1,512,423		1,404,904
	$	1,572,784	$	1,508,265
Liabilities and stockholders’ equity
Liabilities
Accounts payable	$	8,108	$	8,077
Notes payable to subsidiaries		10,922		6,314
Long-term debt		401,000		460,500
Loan from HEI Preferred Funding, LP (8.36% due in 2017)		103,000		103,000
Other		3,454		685
Net liabilities of discontinued operations		—		24
		526,484		578,600
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: 36,809 shares and 35,600 shares		839,503		787,374
Retained earnings		176,118		147,837
Accumulated other comprehensive income (loss)		30,679		(5,546	)
		1,046,300		929,665
	$	1,572,784	$	1,508,265
Note to Balance Sheets
Long-term debt consisted of the following:
Promissory notes, 6.2 - 7.6%, due in various years from 2003 through 2014	$	301,000	$	360,500
Promissory note, 5.5%, due in 2003		100,000		100,000
	$	401,000	$	460,500

The aggregate payments of principal required subsequent to December 31, 2002 on long-term debt are $136 million in 2003, $1 million in 2004, $37 million in 2005, $110 million in 2006 and $10 million in 2007.

As of December 31, 2002, 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.

68

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)	2002			2001			2000
Revenues 1	$	(3,881	)	$	(5,338	)	$	940
Equity in income from continuing operations of subsidiaries		152,725			143,730			136,998
		148,844			138,392			137,938
Expenses:
Operating, administrative and general		15,633			10,481			7,322
Depreciation of property, plant and equipment		891			1,047			1,347
Taxes, other than income taxes		460			472			315
		16,984			12,000			8,984
Operating income		131,860			126,392			128,954
Interest expense		37,576			43,539			40,195
Income from continuing operations before income tax benefits		94,284			82,853			88,759
Income tax benefits		23,933			24,893			20,577
Income from continuing operations		118,217			107,746			109,336
Loss from discontinued subsidiary operations		—			(24,041	)		(63,592	)
Net income	$	118,217		$	83,705		$	45,744

¹ 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 May and July 2001. 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.

69

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)	2002			2001			2000
Cash flows from operating activities
Income from continuing operations	$	118,217		$	107,746		$	109,336
Adjustments to reconcile income from continuing operations to net cash provided by operating activities
Equity in net income of continuing subsidiaries		(152,725	)		(143,730	)		(136,998	)
Common stock dividends/distributions received from subsidiaries		78,599			62,944			93,661
Depreciation of property, plant and equipment		891			1,047			1,347
Other amortization		500			579			447
Writedowns of income notes		4,499			8,652			—
Deferred income taxes		(6,495	)		(6,778	)		(1,569	)
Changes in assets and liabilities
Decrease (increase) in accounts receivable		239			(638	)		131
Increase (decrease) in accounts payable		31			(346	)		1,905
Increase (decrease) in taxes accrued		10,988			(47,603	)		44,487
Changes in other assets and liabilities		5,266			4,709			(13,457	)
Net cash provided by (used in) operating activities		60,010			(13,418	)		99,290
Cash flows from investing activities
Net decrease (increase) in advances to and notes receivable from subsidiaries		42,697			(39,533	)		(8,764	)
Purchase of investments		—			(27,929	)		—
Capital expenditures		(396	)		(916	)		(622	)
Additional investments in subsidiaries		(325	)		(1,424	)		(485	)
Other		480			16			10
Net cash provided by (used in) investing activities		42,456			(69,786	)		(9,861	)
Cash flows from financing activities
Net increase (decrease) in notes payable to subsidiaries with original maturities of three months or less		4,608			2,675			(2,340	)
Net decrease in commercial paper		—			—			(44,820	)
Proceeds from issuance of long-term debt		—			100,000			100,000
Repayment of long-term debt		(59,500	)		(60,500	)		(10,500	)
Net proceeds from issuance of common stock		32,451			78,937			14,080
Common stock dividends		(73,412	)		(67,015	)		(68,624	)
Net cash provided by (used in) financing activities		(95,853	)		54,097			(12,204	)
Net cash provided by (used in) discontinued operations		(709	)		47,585			(77,304	)
Net increase (decrease) in cash and equivalents		5,904			18,478			(79	)
Cash and equivalents, January 1		19,155			677			756
Cash and equivalents, December 31	$	25,059		$	19,155		$	677

Supplemental disclosures of noncash activities:

In 2002, 2001 and 2000, $0.8 million, $0.8 million and $0.7 million, respectively, of HEI advances to HEIDI were converted to equity in noncash transactions.

In April 2000, HEI recommenced issuing new common shares under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP). From March 1998 to March 2000, HEI had acquired for cash its common shares in the open market to satisfy the requirements of the HEI DRIP. Under the HEI DRIP, common stock dividends reinvested by shareholders in HEI common stock in noncash transactions amounted to $17 million in 2002, $16 million in 2001 and $12 million in 2000.

70

Hawaiian Electric Industries, Inc.

and Hawaiian Electric Company, Inc.

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

Years ended December 31, 2002, 2001 and 2000

Col. A	Col. B		Col. C					Col. D			Col. E
(in thousands)			Additions
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts			Deductions			Balance at end of period
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
2000
Allowance for uncollectible accounts–Hawaiian Electric Company, Inc. and subsidiaries	$	1,057	$	1,403	$	948		$	2,469		$	939
Other companies		61		—		—			61			—
	$	1,118	$	1,403	$	948	(a)	$	2,530	(b)	$	939
Allowance for uncollectible interest (ASB)	$	5,695		—		—		$	2,717		$	2,978
Allowance for losses for loans receivable (ASB)	$	35,348	$	13,050	$	2,389	(a)	$	13,338	(b)	$	37,449

(a) Primarily bad debts recovered.

(b) Bad debts charged off.

71

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	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).
4.3	Indenture, dated as of October 15, 1988, between HEI and Citibank, N.A., as Trustee (Exhibit 4 to Registration No. 33-25216).
4.4	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(a)	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(b)	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).
4.5	Pricing Supplements Nos. 1 through 9 to the Registration Statement on Form S-3 of HEI (Registration No. 33-58820) filed in connection with the sale of Medium-Term Notes, Series B (Exhibit 4(b) to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1993, File No. 1-8503).

72

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. 20 to Registration Statement on Form S-3 of HEI (Registration No. 33-58820) filed on February 6, 1998 in connection with the sale of Medium-Term Notes, Series B.
4.5(h)	Pricing Supplement No. 22 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(i)	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(j)	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(k)	Pricing Supplement No. 2 to Registration Statement on Form S-3 of HEI (Registration No. 333-73225) filed on April 11, 2000 in connection with the sale of Medium-Term Notes, Series C.
4.5(l)	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.

73

Exhibit no.	Description
4.5(m)	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(n)	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).
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).

74

Exhibit no.	Description
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.
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).
10.6	1987 Stock Option and Incentive Plan of HEI as amended and restated effective June 19, 2001 (Exhibit 4 to HEI’s Current Report on Form 8-K, dated June 19, 2001, File No. 1-8503).
*10.7	HEI Long-Term Incentive Plan.
*10.8(a)	HEI Supplemental Executive Retirement Plan effective as of January 1, 1989.
*10.8(b)	HEI Excess Pay Supplemental Executive Retirement Plan.
*10.9	HEI Excess Benefit Plan effective as of January 1, 1994.
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.
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).

75

Exhibit no.	Description
*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.
*10.16	HEI Executive Death Benefit Plan of HEI and Participating Subsidiaries effective September 1, 2001.
*11	Computation of Earnings per Share of Common Stock. Filed herein as page 84.
*12	Computation of Ratio of Earnings to Fixed Charges. Filed herein as pages 85 and 86.
*13.1	HEI’s 2002 Annual Report to Stockholders (Appendix A to the Proxy Statement prepared for the Annual Meeting to Stockholders to be held on April 22, 2003)
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 pages 88 and 89.
*23	Accountants’ Consent. Filed herein as page 91.
*99.1	Written Statement 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 92.
*99.2	Written Statement 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 93.
*99.3	Amendment 2002-3 to the Hawaiian Electric Industries Retirement Savings Plan for incorporation by reference in the Registration Statement on Form S-8 (Regis. No. 333-02103).
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	Statement of Issuance of Preferred or Special Classes in Series for HECO Series R Preferred Stock (Exhibit 3.1(a) 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 3.1(b) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989, File No 1-4955).
3(i).4	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).

76

Exhibit no.	Description
*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.
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).
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).

77

Exhibit no.	Description
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).
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	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(a)	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(b)	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(c)	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(d)	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(e)	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).

78

Exhibit no.	Description
10.2	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(a)	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(b)	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).
10.2(c)	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).
10.3	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(a)	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(b)	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	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(a)	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(b)	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).

79

Exhibit no.	Description
10.4(c)	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(d)	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).
10.4(e)	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(f)	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	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(a)	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(b)	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(c)	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(d)	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).

80

Exhibit no.	Description
10.6	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(a)	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(b)	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(c)	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).
10.7	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(a)	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(b)	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(c)	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(d)	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).

81

Exhibit no.	Description
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).
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 page 4 of HECO’s Annual Report.
*12	Computation of Ratio of Earnings to Fixed Charges. Filed herein as page 87.
*13.2	Pages 1 to 2, 4 to 57 and 59 of HECO’s Annual Report (with the exception of the data incorporated by reference in Part I, Part II, Part III and Part IV, no other data appearing in the 2002 Annual Report to Stockholder is to be deemed filed as part of this Form 10-K Annual Report)
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).

82

Exhibit no.	Description
*21	Subsidiaries of HECO. Filed herein as page 90.
*99.1	Written Statement 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 94.
*99.2	Written Statement 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 95.
*99.3	Reconciliation of electric utility operating income per HEI and HECO Consolidated Statements of Income. Filed herein as page 96.

83

HEI Exhibit 11

Hawaiian Electric Industries, Inc.

COMPUTATION OF EARNINGS PER SHARE

OF COMMON STOCK

Years ended December 31, 2002, 2001, 2000, 1999 and 1998

(in thousands, except per share amounts)	2002		2001			2000			1999		1998
Net income (loss)
Continuing operations	$	118,217	$	107,746		$	109,336		$	96,426	$	97,262
Discontinued operations		—		(24,041	)		(63,592	)		421		(12,451	)
	$	118,217	$	83,705		$	45,744		$	96,847	$	84,811
Weighted-average number of common shares outstanding		36,278		33,754			32,545			32,188		32,014
Adjusted weighted-average number of common shares outstanding		36,477		33,942			32,687			32,291		32,129
Basic earnings (loss) per common share
Continuing operations	$	3.26	$	3.19		$	3.36		$	3.00	$	3.04
Discontinued operations		—		(0.71	)		(1.95	)		0.01		(0.39	)
	$	3.26	$	2.48		$	1.41		$	3.01	$	2.65
Diluted earnings (loss) per common share
Continuing operations	$	3.24	$	3.18		$	3.35		$	2.99	$	3.03
Discontinued operations		—		(0.71	)		(1.95	)		0.01		(0.39	)
	$	3.24	$	2.47		$	1.40		$	3.00	$	2.64

84

HEI Exhibit 12 (page 1 of 2)

Hawaiian Electric Industries, Inc.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

Years ended December 31, 2002, 2001, 2000, 1999 and 1998

	2002						2001						2000
(dollars in thousands)	(1)			(2)			(1)			(2)			(1)			(2)
Fixed charges
Total interest charges (3)	$	151,543		$	225,174		$	175,780		$	292,311		$	196,980		$	316,172
Interest component of rentals		4,501			4,501			4,268			4,268			4,332			4,332
Pretax preferred stock dividend requirements of subsidiaries		3,069			3,069			3,069			3,069			3,109			3,109
Preferred securities distributions of trust subsidiaries		16,035			16,035			16,035			16,035			16,035			16,035
Total fixed charges	$	175,148		$	248,779		$	199,152		$	315,683		$	220,456		$	339,648
Earnings
Pretax income from continuing operations	$	181,909		$	181,909		$	165,903		$	165,903		$	170,495		$	170,495
Fixed charges, as shown		175,148			248,779			199,152			315,683			220,456			339,648
Interest capitalized		(1,855	)		(1,855	)		(2,258	)		(2,258	)		(2,922	)		(2,922	)
Earnings available for fixed charges	$	355,202		$	428,833		$	362,797		$	479,328		$	388,029		$	507,221
Ratio of earnings to fixed charges		2.03			1.72			1.82			1.52			1.76			1.49

(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.

85

HEI Exhibit 12 (page 2 of 2)

Hawaiian Electric Industries, Inc.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

Years ended December 31, 2002, 2001, 2000, 1999 and 1998—Continued

	1999						1998
(dollars in thousands)	(1)			(2)			(1)			(2)
Fixed charges
Total interest charges (3)	$	158,947		$	279,285		$	144,911		$	286,980
Interest component of rentals		4,370			4,370			3,559			3,559
Pretax preferred stock dividend requirements of subsidiaries		3,407			3,407			9,379			9,379
Preferred securities distributions of trust subsidiaries		16,025			16,025			12,557			12,557
Total fixed charges	$	182,749		$	303,087		$	170,406		$	312,475
Earnings
Pretax income from continuing operations	$	155,129		$	155,129		$	155,283		$	155,283
Fixed charges, as shown		182,749			303,087			170,406			312,475
Interest capitalized		(2,576	)		(2,576	)		(5,915	)		(5,915	)
Earnings available for fixed charges	$	335,302		$	455,640		$	319,774		$	461,843
Ratio of earnings to fixed charges		1.83			1.50			1.88			1.48

(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.

86

HECO Exhibit 12

Hawaiian Electric Company, Inc.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

Years ended December 31, 2002, 2001, 2000, 1999 and 1998

(dollars in thousands)	2002			2001			2000			1999			1998
Fixed charges
Total interest charges	$	44,232		$	47,056		$	49,062		$	48,461		$	47,921
Interest component of rentals		663			728			696			784			730
Pretax preferred stock dividend requirements of subsidiaries		1,434			1,433			1,438			1,479			4,081
Preferred securities distributions of trust subsidiaries		7,675			7,675			7,675			7,665			4,197
Total fixed charges	$	54,004		$	56,892		$	58,871		$	58,389		$	56,929
Earnings
Income before preferred stock dividends of HECO	$	91,285		$	89,380		$	88,366		$	76,400		$	84,230
Fixed charges, as shown		54,004			56,892			58,871			58,389			56,929
Income taxes (see note below)		56,658			55,416			55,375			48,047			54,572
Allowance for borrowed funds used during construction		(1,855	)		(2,258	)		(2,922	)		(2,576	)		(5,915	)
Earnings available for fixed charges	$	200,092		$	199,430		$	199,690		$	180,260		$	189,816
Ratio of earnings to fixed charges		3.71			3.51			3.39			3.09			3.33
Note:
Income taxes is comprised of the following:
Income tax expense relating to operating income from regulated activities	$	56,729		$	55,434		$	55,213		$	48,281		$	54,719
Income tax expense (benefit) relating to results from nonregulated activities		(71	)		(18	)		162			(234	)		(147	)
	$	56,658		$	55,416		$	55,375		$	48,047		$	54,572

87

HEI Exhibit 21 (Page 1 of 2)

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 10, 2003. 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)

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)

ASB Service Corporation (Hawaii)

AdCommunications, Inc. (Hawaii)

American Savings Mortgage Co., Inc. (Hawaii)

ASB Realty Corporation (Hawaii)

Pacific Energy Conservation Services, Inc. (Hawaii)

HEI District Cooling, Inc. (Hawaii) (currently inactive)

ProVision Technologies, Inc. (Hawaii)

HEI Properties, Inc. (Hawaii)

HEI Leasing, Inc. (Hawaii) (currently inactive)

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 business trust) (Delaware)

Hawaiian Electric Industries Capital Trust II (a business trust) (Delaware) (at all times inactive entities)

Hawaiian Electric Industries Capital Trust III (a business trust) (Delaware) (at all times inactive entities)

The Old Oahu Tug Service, Inc. (Hawaii) (currently inactive)

88

HEI Exhibit 21 (Page 2 of 2)

Hawaiian Electric Industries, Inc.

SUBSIDIARIES OF THE REGISTRANT

(continued)

Discontinued operations:

HEI Power Corp. (Hawaii)

HEI Power Corp. Saipan (Commonwealth of the Northern Mariana Islands) (dissolved on March 18, 2003)

HEI Power Corp. International (Cayman Islands)

HEI Power Corp. Philippines (Cayman Islands)

HEIPC Philippine Development, LLC (Cayman Islands)

Lake Mainit Power, LLC (Cayman Islands) (certified to be dissolved on March 31, 2003)

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)

89

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 10, 2003. 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 business trust) (Delaware)

HECO Capital Trust II (a business trust) (Delaware)

Renewable Hawaii, Inc. (Hawaii)

90

HEI Exhibit 23

[KPMG LLP letterhead]

Accountants’ Consent

The Board of Directors

Hawaiian Electric Industries, Inc.:

We consent to incorporation by reference in Registration Statement Nos. 333-18809, 333-56312 and 333-87782 on Form S-3 and Registration Statement Nos. 33-65234, 333-05667 and 333-02103 on Form S-8 of Hawaiian Electric Industries, Inc., and Registration Statement Nos. 333-18809-01, 333-18809-02, 333-18809-03 and 333-18809-04 on Form S-3 of Hawaiian Electric Industries Capital Trust I, Hawaiian Electric Industries Capital Trust II, Hawaiian Electric Industries Capital Trust III and HEI Preferred Funding, LP of our report dated January 20, 2003, relating to the consolidated balance sheets of Hawaiian Electric Industries, Inc. and subsidiaries as of December 31, 2002 and 2001, 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, 2002, which report is incorporated by reference in the 2002 annual report on Form 10-K of Hawaiian Electric Industries, Inc. We also consent to incorporation by reference of our report dated January 20, 2003 relating to the financial statement schedules of Hawaiian Electric Industries, Inc. in the aforementioned 2002 annual report on Form 10-K, which report is included in said Form 10-K.

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 18, 2003

91

HEI Exhibit 99.1

Hawaiian Electric Industries, Inc.

Written Statement of Chief Executive Officer 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 for the year ended December 31, 2002 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, 2002 and results of operations for the year ended December 31, 2002 of HEI and its subsidiaries.

/s/ Robert F. Clarke

Robert F. Clarke

Chairman, President and Chief Executive Officer of HEI

Date: March 18, 2003

92

HEI Exhibit 99.2

Hawaiian Electric Industries, Inc.

Written Statement of Chief Financial Officer 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 for the year ended December 31, 2002 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, 2002 and results of operations for the year ended December 31, 2002 of HEI and its subsidiaries.

/s/ Eric K. Yeaman

Eric K. Yeaman

Financial Vice President, Treasurer and Chief Financial Officer of HEI

Date: March 18, 2003

93

HECO Exhibit 99.1

Hawaiian Electric Company, Inc.

Written Statement of Chief Executive Officer 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 for the year ended December 31, 2002 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, 2002 and results of operations for the year ended December 31, 2002 of HECO and its subsidiaries.

/s/ T. Michael May

T. Michael May

President and Chief Executive Officer of HECO

Date: March 18, 2003

94

HECO Exhibit 99.2

Hawaiian Electric Company, Inc.

Written Statement of Chief Financial Officer 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 for the year ended December 31, 2002 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, 2002 and results of operations for the year ended December 31, 2002 of HECO and its subsidiaries.

/s/ Richard A. von Gnechten

Richard A. von Gnechten

Financial Vice President

(Principal Financial Officer of HECO)

Date: March 18, 2003

95

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,
(in thousands)	2002			2001			2000
Operating income from regulated and nonregulated activities before income taxes (per HEI Consolidated Statements of Income)	$	194,956		$	193,945		$	193,091
Deduct:
Income taxes on regulated activities		(56,729	)		(55,434	)		(55,213	)
Revenues from nonregulated activities		(4,247	)		(4,992	)		(6,535	)
Add:
Expenses from nonregulated activities		1,177			1,813			1,818
Operating income from regulated activities after income taxes (per HECO Consolidated Statements of Income)	$	135,157		$	135,332		$	133,161

96

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		Richard A. von Gnechten
	Financial Vice President, Treasurer and Chief Financial Officer of HEI		Financial Vice President of HECO
	(Principal Financial Officer of HEI)		(Principal Financial Officer of HECO)
Date: March 18, 2003		Date: March 18, 2003

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrants and in the capacities indicated on March 18, 2003. The execution of this report by each of the undersigned who signs this report solely in such person’s capacity as a director or officer of Hawaiian Electric Company, Inc. shall be deemed to relate only to matters having reference to such registrant and its subsidiaries.

Signature	Title
/s/ Robert F. Clarke	Chairman, President and Chairman of the Board of Directors of HEI
Robert F. Clarke	Chairman of the Board of Directors of HECO
	(Chief Executive Officer of HEI)
/s/ T. Michael May	Director of HEI
T. Michael May	President and Director of HECO
	(Chief Executive Officer of HECO)
/s/ Eric K. Yeaman	Financial Vice President, Treasurer and Chief Financial Officer of HEI
Eric K. Yeaman	(Principal Financial Officer of HEI)
/s/ Curtis Y. Harada	Controller of HEI
Curtis Y. Harada	(Principal Accounting Officer of HEI)

97

SIGNATURES (continued)

Signature	Title
/s/ Richard A. von Gnechten	Financial Vice President
Richard A. von Gnechten	(Principal Financial Officer of HECO)
/s/ Ernest T. Shiraki	Controller of HECO
Ernest T. Shiraki	(Principal Accounting Officer of HECO)
/s/ Don E. Carroll	Director of HEI
Don E. Carroll
/s/ Shirley J. Daniel	Director of HEI and HECO
Shirley J. Daniel
/s/ Constance H. Lau	Director of HEI
Constance H. Lau
	Director of HEI
Victor Hao Li
/s/ Bill D. Mills	Director of HEI
Bill D. Mills
	Director of HEI
A. Maurice Myers

98

SIGNATURES (continued)

Signature	Title
/s/ Diane J. Plotts	Director of HEI and HECO
Diane J. Plotts
/s/ James K. Scott	Director of HEI and HECO
James K. Scott
/s/ Oswald K. Stender	Director of HEI
Oswald K. Stender
/s/ Anne M. Takabuki	Director of HECO
Anne M. Takabuki
/s/ Barry K. Taniguchi	Director of HECO
Barry K. Taniguchi
/s/ Kelvin H. Taketa	Director of HEI
Kelvin H. Taketa
/s/ Jeffrey N. Watanabe	Director of HEI and HECO
Jeffrey N. Watanabe

99

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 annual report on Form 10-K of Hawaiian Electric Industries, Inc. (HEI);

2. Based on my knowledge, this annual 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 annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual 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 annual report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures 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 annual report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

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

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 18, 2003

/s/ Robert F. Clarke

Robert F. Clarke

Chairman, President and Chief Executive Officer

100

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 annual report on Form 10-K of Hawaiian Electric Industries, Inc. (HEI);

2. Based on my knowledge, this annual 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 annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual 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 annual report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures 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 annual report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

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

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 18, 2003

/s/ Eric K. Yeaman

Eric K. Yeaman

Financial Vice President, Treasurer and Chief Financial Officer

101

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 annual report on Form 10-K of Hawaiian Electric Company, Inc. (HECO);

2. Based on my knowledge, this annual 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 annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual 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 annual report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures 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 annual report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

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

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 18, 2003

/s/ T. Michael May

T. Michael May

President and Chief Executive Officer

102

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 annual report on Form 10-K of Hawaiian Electric Company, Inc. (HECO);

2. Based on my knowledge, this annual 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 annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual 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 annual report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures 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 annual report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

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

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 18, 2003

/s/ Richard A. von Gnechten

Richard A. von Gnechten

Financial Vice President

103

EX-4.1

HECO Exhibit 4.1

HECO agrees to furnish to the Securities and Exchange Commission upon request copies of the instruments which define the rights of holders of current and future long-term debt of HECO, HELCO and MECO, including loan agreements, notes and guarantees issued by them in connection with the issuance for their benefit by the Department of Budget and Finance of the State of Hawaii of special purpose revenue bonds (including refunding special purpose revenue bonds).

Hawaiian Electric Company, Inc.
By	/s/ Richard A. von Gnechten
	Richard A. von Gnechten
	Financial Vice President
Date:	March 18, 2003

EX-10.4

HEI Exhibit 10.4

HAWAIIAN ELECTRIC INDUSTRIES, INC.

EXECUTIVE INCENTIVE COMPENSATION PLAN

Hawaiian Electric Industries, Inc. (HEI) establishes and adopts the following Executive Incentive Compensation Plan (EICP).

1. PURPOSE

The purpose of the EICP is to encourage high level of performance by HEI and its subsidiaries (Company) through the establishment of specific financial and/or nonfinancial goals, the accomplishment of which will require a high degree of competence and diligence on the part of certain key employees of the Company selected to participate in the EICP, and will be beneficial to the owners and customers of the Company.

2. DEFINITIONS

The following definitions apply to the EICP:

2.1 “Award” means payment made in accordance with the provisions of the EICP.

2.2 “Board of Directors” means the Board of Directors of HEI.

2.3 “Board’s Compensation Committee” means the Compensation Committee of the Board of Directors.

2.4 “Committee” means the President and CEO of HEI, the financial Vice President of HEI, the Director, Compensation (or equivalent) of Hawaiian Electric Company, Inc. (HECO) and such other person as may be appointed by the President and CEO of HEI.

2.5 “Deferred Account” means an unfunded account within which a Participant’s deferred Awards and accrued interest are accumulated.

2.6 “Executives” means the senior officers and managers responsible for determining business and strategic policies.

2.7 “Participant” means an employee selected to participate in the EICP.

2.8 “Performance Goals” means the performance objectives of the Company established for the purpose of determining the amount of any incentive awarded during a Plan Year.

2.9 “Plan Year” means the calendar year.

2.10 “Incentive Award” means the level of incentive Award associated with full achievement of Performance Goals.

3. BASIC PLAN CONCEPT

The EICP provides an opportunity for Participants to earn annual incentive compensation Awards depending on the level of Company and individual performance. Performance will be based on a twelve-month period beginning January 1 and ending December 31. Awards may be in cash or stock at the option of the Board of Directors. Awards to Participants are based primarily on Company Performance Goals and may be partially on other factors including individual Performance Goals. Minimum performance “hurdles” will be established that must be exceeded before any Award is made. Unless otherwise specified, the minimum performance hurdle for each individual will be the minimum of the performance target range for the Earnings Per Share or Company income goal listed. The minimum earnings goal and the minimum performance goal for each individual must both be met for an award to be made. When Awards are granted, payments are made in cash and/or Company stock shortly after the end of each Plan Year unless voluntarily deferred by the Participant. Stock awards are subject to the availability of authorized and unissued shares, and the Board of Directors shall determine the class, rights, privileges, restrictions, qualifications, and amounts of stock to be granted, if any.

4. ADMINISTRATION

The EICP will be administered by the Committee which shall, subject to the provisions of the EICP, make recommendations to the Board’s Compensation Committee regarding:

4.1 Participants;

4.2 Performance Goals;

4.3 Incentive Awards;

4.4 Amount of the actual Award that may be made to each Participant and whether it should be granted in cash and/or stock, and if in stock, the nature of the stock to be granted; and

4.5 Policies and regulations for the administration of the EICP. Except for Subsection 4.2. Performance Goals, the Board’s Compensation Committee shall have the authority to act upon the recommendations, made in accordance with the preceding sentence, of the Committee for all Participants other than the President and CEO, HEI, and the presidents of HEI subsidiaries. The Board’s Compensation Committee shall submit its recommendations for all Performance Goals to the Board of Directors for its approval. With respect to the Awards to be made under the EICP to the President and CEO, HEI and the presidents of HEI subsidiaries, and also with respect to any and all matters included in this subsection and any changes affecting such Participants, the Board’s Compensation Committee shall submit its recommendations to the Board of Directors for its approval.

5. PARTICIPATION

Participants will be selected from those of the Company whose decisions contribute directly to the annual success of the Company. No employee will at any time have the automatic right to be selected as a Participant in the EICP for any Plan Year, nor, if so selected, to be entitled automatically to an Award, nor, having been selected as a Participant for one Plan Year, to be automatically selected as a Participant in any subsequent Plan Year.

6. PERFORMANCE GOALS

Performance Goals will be designed to accomplish such financial and strategic objectives which are consistent with and supportive of the policies, goals and objectives of the Board of Directors. Performance Goals for any Plan Year may be adjusted in recognition of: extraordinary or nonrecurring events experienced by the Company during the Plan Year; changes in applicable accounting rules or principles; or change in the Company’s methods of accounting during the Plan Year.

7. INCENTIVE AWARDS

The Incentive Award for each Participant will be calculated by applying an Incentive Award percentage to each Participant’s salary range midpoint.

8. DETERMINATION OF AWARDS

Subject to the provisions of Section 6 and 7, Awards for each Plan Year will consider actual performance of the Company for such Plan Year in relation to the established Performance Goals and, with the exception of the President and CEO, HEI, and the presidents of HEI subsidiaries, management’s recommendation for individual Award adjustments that reflect each Participant’s contribution to overall Company performance.

9. PAYMENT OF AWARDS

9.1 Payment of Nondeferred Awards - The payment of Awards for any Plan Year will be made in cash or stock to the Participant as soon as practical after the close of the Plan year unless the Participant irrevocably elected to defer payment of a portion of the Award, as provided in subparagraph 9.2 below by filing a written election form with the Committee before the beginning of the Plan Year.

9.2 Payment of Deferred Cash Awards - Each deferred Award will be credited to the Participant’s Deferred Account and will be paid to the Participant, or to his or her beneficiary or estate in the event of his or her death, at the end of the deferral period in a lump sum or in installments, as provided in the written election form. Amounts credited to an Eligible Participants’ account shall be credited with an amount equivalent to the interest compounded quarterly, at the annual rate commensurate with the prevailing interest rate on three-year certificates of deposit at American Savings Bank, F.S.B., as of January 1 of that year; provided, however, that the balance of the Participant’s Deferred Account as of December 31, 1990 shall continue to be credited with interest at the rate of 2.5% per quarter, compounded quarterly. Such Deferred Account will be credited with interest from the date the Award is granted to the date of receipt by the executive under the Deferral Agreement. Despite any contrary provisions in the Participant’s written election form, the Committee in its sole discretion may decide to pay the balance in a Participant’s Deferred Account in a lump sum as soon as practical after the end of the Plan Year during which the Participant is no longer employed by the Company for any reason.

In the event the payout of any portion of the awards are in HEI Common Stock, the number of shares of stock to be issued will be based on Average Fair Market Value. “Average Fair Market Value” means an amount equal to the average of the high and low sales prices of HEI Common Stock on the composite tape for stocks listed on the New York Stock Exchange as quoted in the Composite Transactions published in the Western Edition of the Wall Street Journal for the day the EICP award payout is approved by the HEI Compensation Committee. If the HEI Stock is not admitted to trade on the New York Stock Exchange, the Average Fair Market Value shall be determined by the HEI Compensation Committee in such other reasonable manner as it shall decide.

10. ASSIGNMENTS AND TRANSFERS

Participants will not assign, encumber, or transfer their rights and interests under the EICP. Any attempt to do so will render those rights and interests null and void.

11. EMPLOYEE RIGHTS UNDER THE EICP

No employee or other person will have any claim or right to be granted an Award under this EICP. Neither the EICP nor any action taken thereunder will be construed as giving any employee any right to be retained in the employ of the Company or any of its divisions or subsidiaries.

12. WITHHOLDING TAXES

The Company will withhold the amount of any federal, state, or local income taxes attributable to any amounts payable under the EICP.

13. OTHER PLANS

The payments and benefits under this EICP will be excluded as compensation under all other Company compensation and benefits plans.

14. CHANGES AND TERM

Changes, amendments or modifications to the EICP shall only be made by the Board’s Compensation Committee, subject to approval of the Board of Directors. The Board of Directors may amend, suspend, or terminate the EICP or any portion of it at any time.

Amended 1/25/96 CMM

Approved HEI BOD

EX-10.7

HEI Exhibit 10.7

HAWAIIAN ELECTRIC INDUSTRIES, INC.

LONG-TERM INCENTIVE PLAN

General Terms

The Compensation Committee of the Board of Directors of Hawaiian Electric Industries, Inc. (HEI) establishes and adopts the following Long-Term Incentive Plan (LTIP).

1. PURPOSE

The purpose of the LTIP is to encourage a high level of sustained Company performance through the establishment of specific long-term financial goals, the accomplishment of which will require a high degree of competence and diligence on the part of certain key employees of the Company selected to participate in the LTIP and will be beneficial to the owners and customers of the Company.

2. DEFINITIONS

The following definitions apply to the LTIP:

2.1 “Award” means payment made in accordance with the provisions of the LTIP.

2.2 “Compensation Committee” means the Compensation Committee of the Board of Directors of HEI.

2.3 “Deferred Account” means an account within which payments for Awards and accrued interest may be accumulated.

2.4 “Executive” means the officers and managers responsible for determining business and strategic policies.

2.5 “Participant” means an employee selected to participate in the LTIP.

2.6 “Performance Goals” means the performance objectives of HEI established for the purpose of determining the amount of any award for a Performance Period.

2.7 “Performance Period” means the three-year period over which performance is measured.

- 1 -

3. BASIC PLAN CONCEPT

The LTIP provides an opportunity for Participants to earn incentive compensation Awards depending on the level of HEI and individual performance. Except for the commencement of the initial year of this LTIP, performance will be based on a three-year period beginning January 1 of the first year of the Performance Period and ending December 31 of the third year of the Performance Period. The Compensation Committee will determine when the Performance Period for the first year of the initial Performance Period shall commence. Awards may be in cash or stock at the option of the Compensation Committee. Awards may be based on HEI performance plus additional goals or objectives. After the Awards are approved by the Compensation Committee, payments will be made in cash and/or HEI stock during the year following the end of each Performance Period unless voluntarily deferred by the Participant.

4. ADMINISTRATION

The Compensation Committee shall administer the Plan and will make the following determinations:

4.1 Selection of Participants.

4.2 Determination of Performance Goals and LTIP for each Performance Period.

4.3 Determination of the amount of the Award to be made to each Participant.

5. PARTICIPATION

The Compensation Committee will select Participants from those executives whose decisions and actions contribute directly to HEI’s long-term success. No employee will have the automatic right to be selected as a Participant in the LTIP for any Performance Period, nor, if so selected, be entitled automatically to an Award, nor, having been selected as a Participant for one Performance Period, be automatically selected as a Participant in any subsequent Performance Period.

Participants who are placed in the plan after the start of the Performance Period who voluntarily terminate employment within the Performance or transfer to a position that is not included in the LTIP, will be eligible to receive that portion or the award represented by the number of complete months of eligibility during the Performance Period divided by 36.

- 2 -

6. PERFORMANCE GOALS AND LTIP FOR PERFORMANCE PERIOD

The Compensation Committee will establish, for each Performance Period, Performance Goals for each Performance Period designed to accomplish such financial and strategic objectives as it may from time to time determine appropriate. The Compensation Committee will make adjustments to the Performance Goals and the LTIP for any Performance Period as it deems equitable in recognition of: extraordinary or nonrecurring events experienced by HEI during the Performance Period or changes in the Company’s methods of accounting during the Performance Period.

7. DETERMINATION OF AWARDS

Subject to the provisions of Section 6, the Compensation Committee will determine the Awards to be made to each Participant for each Performance Period. Awards made will be based primarily on the level of performance within the performance range, but will also be based on each Participant’s contribution to overall HEI performance during the Performance Period.

8. PAYMENT OF AWARDS

8.1 Payment of Nondeferred Awards – The payment of Awards for any Performance Period will be made in cash or stock to the Participant as soon as practical after the close of the Performance Period unless, in the case of a cash award, the Participant irrevocably elected to defer payment of all or a portion of the Award as provided in subparagraph 8.2 below by filing a written election form with the Compensation Committee before the beginning of the Performance Period or before the executive begins service as a Participant for the Performance Period.

8.2 Payment of Deferred Cash Awards – Each deferred Award will be credited to the Participant’s Deferred Account and will be paid to the Participant, or to the beneficiary of estate in the event of their death, at the end of the deferral period in cash lump sum or in installments, as provided in the written election form. Amounts credited to a Participant’s Deferred Account shall be credited each year with an amount equivalent to interest, compounded quarterly, at the annual rate commensurate with the prevailing interest rate on three-year certificates of deposit at American Savings Bank, F.S.B., as of January 1 of that year; provided, however, that the balance of the Participant’s Deferred Account as of December 31, 1990 shall continue to be credited annually with interest at the rate of ten percent (10%) per annum, compounded quarterly. Such Deferred Account will be credited with interest from the date the Award would

- 3 -

have been paid in cash to the date of receipt by the Participant under the Deferral Agreement. Despite any contrary provisions in the Participant’s written election form, the Compensation Committee, in its sole discretion, may decide to pay the balance in a Participant’s Deferred Account in a lump sum as soon as practical after the Participant’s employment by the Company is terminated for any reason.

9. ASSIGNMENTS AND TRANSFERS

Participants will not assign, encumber, or transfer their rights and interests under the LTIP; any attempt to do so will render Participant’s rights and interests under this LTIP null and void.

10. EMPLOYEE RIGHTS UNDER THE LTIP

10.1 No employee or other person will have any claim or right to be granted an Award under this LTIP. Neither the LTIP nor any action taken under it will be construed as giving any employee any right to be retained in the employ of HEI or any of its affiliated companies.

11. WITHHOLDING TAXES

11.1 HEI will make the proper withholdings of any federal, state, or local income taxes attributable to any amounts payable under the LTIP.

12. OTHER PLANS

12.1 The payments and benefits under this LTIP will be excluded from considered compensation under all other Company compensation and benefit plans.

13. TERM

The Committee may amend, suspend, or terminate the LTIP or any portion of it at any time.

- 4 -

EX-10.8(A)

HEI Exhibit 10.8(a)

HAWAIIAN ELECTRIC INDUSTRIES, INC.

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

TABLE OF CONTENTS

			Page
PROLOGUE			1
ARTICLE I DEFINITIONS			1
ARTICLE II SERVICE RULES
	2.1	Credited Service Rules	3
	2.2	Special Rule for Maternity or Paternity Absences	4
ARTICLE III ELIGIBILITY			4
ARTICLE IV CONTRIBUTIONS			4
ARTICLE V BENEFITS
	5.1	Normal Retirement Income	4
	5.2	Early Retirement Income	5
	5.3	Postponed Retirement Income	5
	5.4	Normal Form of Benefits and Optional Forms	5
	5.5	Death Benefit for Certain Participants	6
	5.6	Special Distribution Rules	7
ARTICLE VI ADMINISTRATION
	6.1	The Committee To Be Named Fiduciary	7
	6.2	Asset Manager	8
	6.3	Plan Administrator	9
	6.4	Expenses	10
ARTICLE VII FIDUCIARY INDEMNIFICATION			10
ARTICLE VIII CLAIMS PROCEDURE			10
ARTICLE IX AMENDMENT, TERMINATION, AND MERGER
	9.1	Amendment	11
	9.2	Termination	11
	9.3	Merger, Etc. of Company	11
ARTICLE X MISCELLANEOUS
	10.1	Right to Employment or Benefits	11
	10.2	Inalienability	12
	10.3	Facility of Payment	12
	10.4	Construction of Plan	12
	10.5	Forms	12
Appendix I Actuarial Assumptions			14

HAWAIIAN ELECTRIC INDUSTRIES, INC.

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

PROLOGUE

Effective as of January 1, 1989, the “Hawaiian Electric Industries, Inc. Supplemental Executive Retirement Plan” (the “Plan”) was adopted by the Company as a spin off from the Hawaiian Electric Industries, Inc. Excess Benefit Plan (the “Excess Benefit Plan”), as amended and restated as of such date. The benefits accrued under the Excess Benefit Plan as of such date by participants of this Plan were spun off to this Plan on January 1, 1989.

This Plan is not intended to meet or be subject to the qualification requirements of (i) Section 401 of the Internal Revenue Code 1986, as amended, or (ii) Section 3(36) of the Employee Retirement Income Security Act of 1974.

ARTICLE I

DEFINITIONS

The following terms as used herein shall have the indicated meaning, unless a different meaning is clearly required by the context. Whenever appropriate, words used in the singular may include the plural and vice versa, and the masculine gender shall always include the feminine gender.

1.1 Accrued Benefit means the Participant’s accrued benefit determined hereunder and expressed in the form of an annual benefit commencing at the Participant’s Normal Retirement Date.

1.2 Actuarial Equivalent means an amount and form of benefit certified by an actuary to be mathematically equivalent in value to a given amount and form of benefit on the basis of the assumptions set forth in Appendix I. Plan benefits that are deemed to be “actuarially reduced,” “actuarially increased,” or “actuarially adjusted” shall be computed as the Actuarial Equivalent of the benefit being replaced.

1.3 Asset Manager means the person designated to manage the assets of the Plan in accordance with Section 6.2.

1.4 Associated Company means the Company and any corporation that is a member of the same controlled group of corporations (within the meaning of Section 1563(a) of the Code, determined without regard to Section 1563(a)(4) and (e)(3)(C) of the Code) as the Company. A corporation shall be regarded as an Associated Company only during the period it is a member of such controlled group of corporations.

1

1.5 Code means the Internal Revenue Code of 1986, as amended.

1.6 Committee means the Pension Investment Committee appointed pursuant to resolution of the Board of Directors of the Company.

1.7 Company means Hawaiian Electric Industries, Inc.

1.8 Compensation means the Participant’s wages, salaries, and bonuses (including for the year for which it is earned any bonus under the Hawaiian Electric Industries, Inc. Executive Incentive Compensation Plan, but excluding any bonus that is paid or deferred pursuant to the Hawaiian Electric Industries, Inc. Long-Term Incentive Plan) received for personal services actually rendered in the course of employment with an Associated Company prior to reduction for an arrangement qualifying under Section 125 or 401(k) of the Code.

1.9 Credited Service means the period of employment for which benefit accrual credit is given under Article II.

1.10 Early Retirement Date means the first day any month not more than ten years prior to a Participant’s Normal Retirement Date, provided that the Participant has completed five years of Credited Service; except that a Participant who has reached 50 years of age may retire on the first day of any month after having completed 15 years of Credited Service. If, however, an active Participant who is eligible for an Early Retirement Date gives at least 30 days advanced written notice of this intent to elect an Early Retirement Date, his Early Retirement Date shall be the day following his last day of employment with an Associated Company and he shall receive a pro rata portion of his early retirement income for the month in which his last day of employment occurs.

1.11 ERISA means the Employee Retirement Income Security Act of 1974, as amended.

1.12 Final Average Compensation means the average annual rate of Compensation of a Participant during the highest three 12-month calendar periods during the Participant’s last 60 months of Credited Service affording the highest such average.

1.13 Normal Retirement Date means the first day of the month in which the Participant reaches 65 years of age if the Participant was born during the first 15 days of the month and the first day of the month next following the month the Participant reaches 65 years of age if the Participant’s birth occurred after the 15^th day of the month. If, however, an active Participant who is eligible for a Normal Retirement Date gives at least 30 days advance written notice of his intent to retire on his Normal Retirement Date, his Normal Retirement Date shall be the day

2

following his last day of employment with an Associated Company and he shall receive a pro rata portion of his normal retirement income for the month in which his last day of employment occurs.

1.14 Participant means an officer of the Company or an Associated Company whose participation in this Plan is approved by resolution of the Compensation Committee of the Board of Directors of Hawaiian Electric Industries, Inc.

1.15 Plan means this Hawaiian Electric Industries, Inc. Supplemental Executive Retirement Plan.

1.16 Plan Administrator means the person designated to administer the Plan in accordance with Section 6.3.

1.17 Plan Year means the calendar year.

1.18 Postponed Retirement Date means, in the case of a Participant who continues in employment after his Normal Retirement Date, the first day of the month following his last day of employment.

1.19 Qualified Joint and Survivor Annuity means an annuity (i) for the life of the Participant with a survivor annuity for the life of the spouse of the Participant to whom he is married at the time his retirement income payments commence that is one-half of the amount of the retirement income payable during the joint lives of the Participant and the Participant’s spouse, and (ii) that is that Actuarial Equivalent of a single life annuity for the life of the Participant.

1.20 Retirement Plan means the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries.

ARTICLE II

SERVICE RULES

Section 2.1 Credited Service Rules

(a) Credited Service shall be granted for the period of time beginning with the initial date on which the Participant commenced employment with an Associated Company to the date the Participant terminates employment with all of the Associated Companies.

(b) If a Participant who was formerly employed by any of the Associated Companies is re-employed by an Associated Company and re-admitted as a Participant of this Plan by the Compensation Committee, in addition to the Credited Service granted in (a), Credited Service shall be granted for the period of time beginning with the date the Participant commences participation after such re-employment to the date the Participant subsequently terminates employment with all of the Associated Companies.

3

Section 2.2 Special Rule for Maternity or Paternity Absences

If a Participant is absent form work for any period (i) by reason of pregnancy, the birth of a child, or the placement of a child with a Participant in connection with the adoption of such child or (ii) for purposes of caring for such child for a period beginning immediately following such birth or placement, the Participant shall not be granted Credited Service for such Period. Such leave shall not, however, be regarded as a period of severance.

ARTICLE III

ELIGIBILITY

An officer of an Associated Company shall be a Participant only if his participation in the Plan has been approved by the Compensation Committee of the Board of Directors of the Company. However, in no event may a Participant in this Plan also be eligible to participate in the Hawaiian Electric Industries, Inc. Excess Benefit Plan or the Hawaiian Electric Industries, Inc. Excess Pay Supplemental Executive Retirement Plan.

ARTICLE IV

CONTRIBUTIONS

The Associated Companies shall pay the entire cost of the Plan from their general assets. No separate trust fund shall be established in connection with the Plan.

ARTICLE V

BENEFITS

Section 5.1 Normal Retirement Income

The monthly amount of retirement income commencing on the Participant’s Normal Retirement Date on a single life basis shall be as follows:

(a) (i) The product of the Participant’s years of Credited Service and 2.04% (but not more than a total of 60%), multiplied by the Participant’s Final Average Compensation reduced by (ii) (1) the Participant’s Primary Social Security Benefit in effect at his date or retirement or other termination of service (calculated as if payments begin at the earliest age at which Social Security Benefits are available), (2) the benefit payable under the Retirement Plan (calculated without regard to the cost of living increases provided for in Section 5.10 of the Retirement Plan) and (3) the benefit of the Participant derived from employer contributions to any other plan maintained by an Associated Company that qualifies under Section 401(a) of the Code (other than the Hawaiian Electric Industries Retirement Savings Plan and the Hawaiian Electric Industries, Inc. Stock Ownership Plan). With regard to (ii)(2) and (3) above, the benefits to be offset

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shall be the applicable plan’s benefit after application of Section 415 of the Code (as it may be amended from time to time).

(b) Notwithstanding any provision herein to the contrary (including the age requirements of this Plan), a Participant shall receive as retirement income (as determined on an annual basis, for benefits not paid in a lump sum) at least the amount which would have been paid pursuant to the benefit formula stated in Section 4.2 of the Hawaiian Electric Industries, Inc. Excess Pay Supplemental Executive Retirement Plan. If benefits are paid in the form of a lump sum, the determination shall include the adjustments described in Section 5.7 and assumed increases in the maximum benefits limitations under Section 415 of the Internal Revenue Code, in accordance with the applicable actuarial assumptions specified in Appendix I for lump sum distributions.

Section 5.2 Early Retirement Income

(a) If a Participant retires on an Early Retirement Date, his monthly retirement income commencing on his Early Retirement Date shall be the retirement income payable pursuant to Section 5.1 of this Plan, reduced to reflect the fact that payments shall commence earlier according to the scale in Appendix I interpolated to the nearest full month; provided, however, that no such reduction may exceed the Actuarial Equivalent reduction permitted to reflect the fact that payment shall commence earlier.

(b) A Participant who has satisfied the Credited Service requirements for an Early Retirement Date, but separated from service with the Participating Employers and the Associated Companies before satisfying the age requirement for an Early Retirement Income, shall be entitled upon satisfaction of such age requirement to a benefit equal to the benefit to which he would be entitled at his Normal Retirement Date, actuarially reduced in accordance with Appendix I.

Section 5.3 Postponed Retirement Income

If a Participant remains employed subsequent to his Normal Retirement Date and retires on a Postponed Retirement Date, his retirement income commencing on his Postponed Retirement Date shall be computed based upon his Credited Service and Compensation (including Credited Service and Compensation credited subsequent to his Normal Retirement Date) as of his Postponed Retirement Date.

Section 5.4 Normal Form of Benefits and Optional Forms

(a) Retirement benefits under this Plan shall begin at the same time and be paid in the same form as the Participant’s benefit under the Retirement Plan, except that the option for the adjustment for Federal Old Age Benefits (Social Security) under

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Section 5.8 of the Retirement Plan shall not be applicable. Such benefit shall be the Actuarial Equivalent of the Participant’s Accrued Benefit, based on the same actuarial assumptions used in determining optional forms of benefits under the Retirement Plan, as included in Appendix I attached.

(b) Notwithstanding the foregoing, a Participant may at any time within the 90-day period ending one (1) year prior to the annuity starting date make a written election, subject to the approval of the Compensation Committee of the Board of Directors, to convert his Accrued Benefit into a lump sum payment that is the Actuarial Equivalent of his Accrued Benefit. During such period, his election may be revoked in writing, in which case benefits will be paid under the same form as benefits under the Retirement Plan, as described in Section 5.4(a).

Section 5.5 Death Benefit for Certain Participants

(a) If a Participant dies prior to commencement of distribution of his Accrued Benefit, his surviving spouse shall automatically receive the appropriate survivor benefit provided in the Retirement Plan; provided, however, that if such Participant dies after attainment of his Early Retirement Date, but before actual retirement, his surviving spouse shall receive a benefit equal to the greater of (i) the appropriate survivor benefit provided in the Retirement Plan or (ii) the “survivor annuity” described in Section 5.5(b) of this Plan. In the event a “survivor annuity” under Section 5.5(b) of this Plan is the greater benefit, the Retirement Plan shall pay so much of that benefit as is permitted under the terms of the Retirement Plan, with the excess being paid from this Plan.

(b) For purposes of this Section 5.5, “survivor annuity” means a survivor annuity for the life of the surviving spouse of the Participant under which the payments to the surviving spouse are not less than the amounts that would be payable as a survivor annuity under a Qualified Joint and Survivor Annuity based on the benefit calculated under Section 5.1 of this Plan. In the case of a Participant who has not attained his Early Retirement Date at the time of death, the survivor annuity shall be calculated as if such Participant had (i) separated from service on his date of death, (ii) survived to his Early Retirement Date, (iii) retired with an immediate Qualified Joint and Survivor Annuity at his Early Retirement Date and (iv) died on the day after the day on which he would have attained his Early Retirement Date. Such survivor annuity shall commence to be paid on the first day of the month following the Participant’s death; provided that, in the case of a Participant who has not attained his Early Retirement Date at the time of death, such survivor annuity shall commence to be paid as of the date the Participant would have been eligible to receive early retirement income. If the present value of the survivor annuity (as determined by using the interest rate that would be used as of the first day of the Plan Year in which the

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distribution occurs by the Pension Benefit Guaranty Corporation for purposes of determining the present value of a lump sum distribution on plan termination) does not exceed $3,500, the Plan shall distribute such value in a lump sum rather than paying such value in the form of an annuity. No such lump sum distribution shall be made (i) if such present value exceeds $3,500 or (ii) after the commencement of payment of any such annuity.

Section 5.6 Special Distribution Rules

(a) A Participant may request that the distribution of benefits under the Plan commence at a date later than his retirement date. This request must be made by submitting to the Plan Administrator a written statement, signed by the Participant, that describes the form of distribution and the date on which the Participant requests payment to commence. The Committee shall determine in its sole discretion whether to grant such request.

(b)    (1) Notwithstanding any other provision of this Plan, if a “change of control” (as defined in Section 5.6(b)(2) occurs, then the Actuarial Equivalent of the Accrued Benefit of each retired Participant (or if the retired Participant has died, the portion of his Accrued Benefit to which his spouse or other beneficiary is entitled) shall be paid in a lump sum to the retired Participant (or if the retired Participant has died, his spouse or other beneficiary) within 30 days of the date of such change in control.

         (2) For the purposes of this Section 5.6(b), a “change of control” shall be deemed to have taken place if (i) any person, including a group as defined in Section 13(d)(3) of the Securities Exchange Act of 1934, becomes the beneficial owner of shares of the Company having 25% or more of the total number of votes that may be cast for the election of Directors of the Company; (ii) as the result of, or in connection with, any cash tender or exchange offer, merger, or other business combination, sale of assets, or contested election, or any combination of the foregoing transactions, the persons who were Directors of the Company before the transaction shall cease to constitute a majority of the Board of Directors of the Company or any successor to the Company; or (iii) a majority of the Board of Directors of the Company determines in good faith that a “change of control” is imminent.

ARTICLE VI

ADMINISTRATION

Section 6.1 The Committee To Be Named Fiduciary

(a) The Committee shall be the “Named Fiduciary” (within the meaning of EIRSA) of the Plan with all responsibility for the operation and administration of the Plan. The Committee shall have the power to delegate specific fiduciary responsibilities of any Associated Company to any person or group of persons, and such

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person or group may serve in more than one such delegated capacity. Such delegations must be accepted in writing and may be to employees of any Associated Company or to other individuals, all of whom shall serve at the pleasure of the Committee, and if full-time employees of any Associated Company, without compensation. Any such person may resign by delivering a written resignation to the Committee.

(b) The Committee shall supervise and review the activities of the Assets Manager and the Plan Administrator.

Section 6.2 Asset Manager

(a) The Asset Manager shall be the person named from time to time by the Board of Directors of the Company and shall be the fiduciary in charge of the financial affairs of the Plan. The Asset Manager shall manage the assets, if any, in accordance with the terms of the Plan and shall have all powers necessary to carry out his duties. If at any time there shall be no Asset Manager or if the Asset Manager shall be unable to perform his duties, the President of the Company shall designate a person to serve as Asset Manager until the Board of Directors of the Company appoints a successor.

(b) The Asset Manager shall have the following specific duties and responsibilities in addition to any other duties specified in the Plan or by applicable law.

(1) The Asset Manager shall have responsibility for legal, actuarial, and accounting services provided to the Plan; may authorize an agent to act on his behalf; and may contract for legal, actuarial, medical, accounting, clerical, and other services to carry out his duties and to discharge his responsibilities.

(2) The Asset Manager shall adopt from time to time actuarial tables and actuarial methods for use in all actuarial calculations, if any, required in connection with the determination of the funding status of the Plan. As an aid to the Asset Manager in connection therewith, the actuary consultant designated by the Asset Manager shall make annual actuarial valuations of the contingent assets and liabilities of the Plan, and shall certify to the Asset Manager the tables, actuarial methods, rates of contribution, and other pertinent data and information that such actuary would recommend for use by the Asset Manager.

(3) The Asset Manager shall be responsible for the maintenance of all financial records of the Plan.

(4) The Asset Manager shall be the Plan’s agent for service of any notice of process authorized by law.

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Section 6.3 Plan Administrator

(a) The Plan Administrator shall be the person named from time to time by the Board of Directors of the Company and shall be the fiduciary in charge of administration of the Plan. The Plan Administrator shall administer the Plan in accordance with its terms, and shall have all powers necessary to carry out his duties. If at any time there shall be no Plan Administrator or if the Plan Administrator shall be unable to perform his duties, the President of the Company shall designate a person to serve as Plan Administrator until the Board of Directors of the Company appoints a successor.

(b) The Plan Administrator shall have the following specific duties and responsibilities in addition to any other duties specified in the Plan or by applicable law.

(1) Subject to the limitations contained in this Plan, the Plan Administrator may adopt rules for the administration of the Plan as he considers desirable, provided such rules do not conflict with the Plan.

(2) The Plan Administrator may authorize an agent to act on his behalf, and may contract for legal, actuarial, medical, accounting, clerical, and other services to carry out the Plan and to discharge his responsibilities.

(3) Except as otherwise expressly provided herein, the Plan Administrator may interpret an construe the Plan, or reconcile inconsistencies to the extent necessary to effectuate the Plan, and such action shall be binding upon all persons.

(4) The Plan Administrator shall adopt from time to time actuarial tables and actuarial methods for use in all actuarial calculations, if any, required in connection with the determination of benefit payments under the Plan. As an aid to the Pan Administrator in connection therewith, the actuary consultant designate by the Asset Mangers shall, if needed, certify to the Plan Administrator the tables, actuarial methods, rates of contribution, and other pertinent data and information that such actuary would recommend for use by the Plan Administrator.

(5) The Plan Administrator shall be responsible for the maintenance of all employee, Participant, and beneficiary records for the Plan. The Plan Administrator shall also be responsible for the maintenance of records, appropriate notifications, and filings in connection with the interest of all Participants or their spouses or contingent annuitants.

(6) The Plan Administrator shall be responsible for the filing and disclosure, if required, of the summary plan description, summary of material modifications, and other

9

disclosure information regarding the provisions of the Plan or rights thereunder that must be provided to Participants and their beneficiaries under the Plan, including specifically all annual reports on Form 5500 and summary annual reports.

Section 6.4 Expenses

The Associated Companies shall pay all expenses of administering the Plan. Such expenses shall include any expenses incurred by an Associated Company, the Committee, the Asset Manager, or the Plan Administrator, including, but not limited to, the payment of professional fees of consultants.

ARTICLE VII

FIDUCIARY INDEMNIFICATION

The Associated Companies shall indemnify and save harmless and/or insure each fiduciary who is an employee or a director of an Associated Company, and may indemnify and/or insure those to whom the Company has delegated its fiduciary duties, against any and all claims, losses, damages, expenses, and liability arising from their responsibilities in connection with this Plan, if the fiduciary acted in good faith and in a manner the fiduciary reasonably believed to be in or not opposed to the best interests of the Plan.

ARTICLE VIII

CLAIMS PROCEDURE

The procedure for claiming benefits under the Plan shall be as follows:

(a) The Plan Administrator shall determine the benefits due hereunder to a Participant, or the Participant’s spouse or contingent annuitant, but a person may file a claim for benefits by written notice to the Plan Administrator.

(b) If a claim is denied in whole or in part, the Plan Administrator shall give the claimant written notice of such denial within 30 days of the filing of the claim. Such notice shall (i) specify the reason or reasons for the denial, (ii) refer to the pertinent Plan provisions on which the denial is based, (iii) describe any additional material or information necessary to perfect the claim and explain the need therefore, and (iv) explain the review procedure described in subparagraph (c) hereof.

(c) The claimant may then appeal the denial of the claim by filing written notice of such appeal with the Committee within 90 days after receipt of the notice of denial. The claimant or any authorized representative may, before or after filing notice of appeal, review any documents pertinent to the claim and submit issues and comments in writing. The Committee shall render a decision on such appeal within 30 days after receipt of the appeal

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(unless a longer period is requested by the claimant), and shall forthwith give written notice of such decision.

ARTICLE IX

AMENDMENT, TERMINATION, AND MERGER

Section 9.1 Amendment

(a) Subject to the provisions hereinafter set forth, the Company reserves the right to amend the Plan at any time, and (to the extent permitted by ERISA) give any such amendment retroactive effect.

(b) The Committee may approve any technical amendments to the Plan (i) necessary to comply with federal law and regulations thereunder or (ii) that do not have a substantial impact on the cost or terms of the Plan. All other amendments must be approved by the Board of Directors of the Company.

Section 9.2 Termination

The Plan is adopted with the expectation that it shall be continued indefinitely, but the continuation of the Plan and the payment of any contribution hereunder is not assumed as a contractual obligation by any Associated Company. Each Associated Company reserves the right to terminate the Plan with respect to its participation at any time. If the Plan is terminated (in full or in part), (i) the then Accrued Benefit under this Plan of each affected Participant shall become 100% vested, and (ii) the Actuarial Equivalent of such Accrued Benefit shall be paid in a lump sum to the Participant or retired Participant (or if the Participant or retired Participant has died, his spouse or other beneficiary) within 30 days of the date of the resolution of the Board of Directors that so terminates the Plan.

Section 9.3 Merger, Etc. of Company

The Company shall not sell substantially all of its assets, merge, or consolidate with any other corporation or organization, or permit its business activities to be taken over by another organization, unless and until the succeeding or continuing corporation or other organization expressly assumes the obligations of the Company and the Associated Companies under this Plan.

ARTICLE X

MISCELLANEOUS

Section 10.1 Right to Employment of Benefits

(a) Nothing contained in the Plan shall be deemed to give any Participant a right to remain in the employment of any of the Associated Companies.

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(b)    (1) Nothing contained in the Plan shall be deemed to give any Participant or beneficiary any right or claim to benefits except as expressly provided in the Plan.

         (2) Notwithstanding any other provision in this Plan, in the event the Company fails to fulfill its obligation to make payments to the Participant, his beneficiary, or any other person entitled to payments under the Plan, the Company shall be liable to such person for any attorney’s fees and other legal costs related to enforcing such person’s claim against the Company.

Section 10.2 Inalienability

No Participant or any person having or claiming to have any interest of any kind or character in or under the Plan shall have any right to sell, assign, transfer, convey, hypothecate, anticipate, or otherwise dispose of such interest, and such interest shall not be subject to any liabilities or obligations of, or any bankruptcy proceedings, claims of creditors, attachment, garnishment, execution, levy, or other legal process against, such person or person’s property.

Section 10.3 Facility of Payment

If any Participant or beneficiary eligible to receive benefits under this Plan is, in the opinion of the Plan Administrator, legally, physically, or mentally incapable of personally receiving and receipting for any payment under the Plan, the Plan Administrator may direct payments to such other person, persons, or institutions who, in the opinion of the Plan Administrator, are then maintaining or having custody of such payee, until claims are made by a duly appointed guardian or other legal representative of such payee. Such payments shall constitute a full discharge of the liability of the Plan to the extent thereof.

Section 10.4 Construction of Plan

(a) The headings of articles and sections are included herein solely for convenience of reference, and if there is any conflict between such headings and the text of the Plan, the text shall be controlling.

(b) To the extent not preempted by ERISA, the Plan shall be governed, construed, administered, and regulated according to the laws of the State of Hawaii.

Section 10.5 Forms

All consents, elections, applications, designations, etc. required or permitted under the Plan must be made on forms prescribed and furnished by the Plan Administrator, and shall be

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recognized only if properly completed, executed, and returned to the Plan Administrator.

TO RECORD the adoption of this amended and restated Plan, Hawaiian Electric Industries, Inc. has caused this document to be executed this 19^th day of April, 1994, effective as of January 1, 1994.

HAWAIIAN ELECTRIC INDUSTRIES, INC.
By	/s/ Peter C. Lewis
	Its V.P.-Administration
By	/s/ Robert F. Clarke
	Its President & CEO

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APPENDIX I

ACTUARIAL ASSUMPTIONS

The following actuarial assumptions shall be utilized for determining Actuarial Equivalents:

Qualified Joint and Survivor Annuity, Contingent Annuitant Option, All Purposes not Otherwise Set Forth in the Plan for Appendix I

Interest: 6.5% per annum compounded annually.

Mortality: The UP-1984 Mortality Table with ages set back two years for Participants and seven years for beneficiaries.

Pop-Up Contingent Annuitant Option

Interest: 6.25% per annum compounded annually.

Mortality: The UP-1984 Mortality table with ages set back seven years for beneficiaries.

Section 5.6(a)

Interest: 8% per annum compounded annually.

Mortality: The UP-1984 Mortality Table with ages set back two years for Participants.

Early Retirement Reduction Factors for Vested Terminated Participants

Interest: 8% per annum compounded annually.

Mortality: The UP-1984 Mortality Table with ages set back two years for Participants.

Lump Sum Distributions

Interest: A rate or rates reflecting current market rates on high-quality fixed income investments with maturities approximating such payments.

Mortality: The UP-1984 Mortality Table applied on a unisex basis.

Section 415 limits: Maximum dollar limits under Section 415 of the Internal Revenue Code, increased at the rate of 4% per annum commencing on the first day of the Plan Year in which the distribution occurs.

In the event of an amendment to the Actuarial Equivalent assumptions used in calculating an alternate form of benefits, a Participant shall receive no less than his Accrued Benefit as of the later of the effective date or the adoption date of such amendment, calculated using the applicable Actuarial Equivalent assumptions in effect immediately prior to such amendment.

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Early Retirement Reduction Factors, effective through December 31, 1995
Age at Retirement*	Remainder Percentage Applicable at Retirement
65 – 60	100%
59	99%
58	98%
57	97%
56	96%
55	95%
54	82%
53	79%
52	76%
51	73%
50	70%
Early Retirement Reduction Factors, effective January 1, 1996
Age at Retirement*	Remainder Percentage Applicable at Retirement
65 – 60	100%
59	99%
58	98%
57	97%
56	96%
55	95%
54	90%
53	85%
52	80%
51	75%
50	70%

* For purposes of determining a Participant’s age at his Early Retirement Date under this scale, a Participant’s actual age shall be increased by one full year for each full year of Vesting Service in excess of 33 years of Credited Service.

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EX-10.8(B)

HEI Exhibit 10.8(b)

HAWAIIAN ELECTRIC INDUSTRIES, INC.

EXCESS PAY

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

PROLOGUE

This Plan is not intended to meet or be subject to (i) the qualification requirements of Section 401 of the Internal Revenue Code of 1986, as amended, or (ii) Section 3(36) and Parts 2, 3 or 4 of the Employee Retirement Income Security Act of 1974.

ARTICLE I

DEFINITIONS

The following terms as used herein shall have the indicated meaning, unless a different meaning is clearly required by the context. Whenever appropriate, words used in the singular may include the plural and vice versa, and the masculine gender shall always include the feminine gender.

1.1 Associated Company means (i) a corporation (other than a Participating Employer) that is a member of the same controlled group of corporations (within the meaning of Section 1563(a) of the Code, determined without regard to Section 1563(a)(4) and (e)(3)(C) of the Code) as a Participating Employer, (ii) an entity (other than a Participating Employer) under common control (within the meaning of Section 414(c) of the Code) with a Participating Employer, or (iii) a member (other than a Participating Employer) of an affiliated service group (within the meaning of Section 414(m) of the Code) with a Participating Employer.

1.2 Asset Manager means the person designated to manage the assets of the Plan in accordance with Section 5.2.

1.3 Code means the Internal Revenue Code of 1986, as amended.

1.4 Committee means the Hawaiian Electric Industries, Inc. Pension Investment Committee appointed pursuant to resolution of the Board of Directors of the Company.

1.5 Company means Hawaiian Electric Industries, Inc.

1.6 ERISA means the Employee Retirement Income Security Act of 1974, as amended.

1.7 Excess Plan means the Hawaiian Electric Industries, Inc. Excess Benefit Plan.

1.8 Participant means any person meeting the eligibility requirements of Article II hereof.

1.9 Participating Employer means the Company and/or any other corporation that is a member of the same controlled group of

2

corporations (as defined in Section 415(b) of the Code) as the Company and to which participation in the Retirement Plan is extended, excluding the Hawaiian Insurance & Guaranty Co., Ltd.

1.10 Plan means this Hawaiian Electric Industries, Inc. Excess Pay Supplemental Executive Retirement Plan.

1.11 Retirement Plan means as to any Participant, whichever one of the following plans in which that individual is a participant: the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries, the American Savings Bank Retirement Plan, or the Hawaiian Tug & Barge Corp./Young Brothers, Limited Salaried Pension Plan.

1.12 Plan Administrator means the person designated to administer the Plan in accordance with Section 5.3.

1.13 SERP means the Hawaiian Electric Industries, Inc. Supplemental Executive Retirement Plan and the American Savings Bank Supplemental Executive Retirement Plan.

ARTICLE II

ELIGIBILITY

Each participant in the Retirement Plan earning compensation (as defined the Retirement Plan) in excess of the limits imposed by Section 401(a)(17) of the Code shall be a Participant in this Plan, excluding any participant: (i) whose benefits are subject to collective bargaining; (ii) not employed by a Participating Employer; or (iii) who is also a participant in the SERP.

The individuals named in Appendix I hereto shall also be considered Participants.

ARTICLE III

CONTRIBUTIONS

No contributions to this Plan from Participants shall be permitted or required.

ARTICLE IV

BENEFITS

Section 4.1 Excess Benefit

This Plan shall provide to each Participant a supplemental benefit to ensure that the full benefits described in the applicable Retirement Plan as of the effective date hereof, including the adjustment in the benefit under such Retirement Plan, any other increase in benefits occurring thereafter, and any

3

portion of such Retirement Plan benefit in excess of the limitations imposed by Section 401(a) (17) of the Code, are paid. Such excess benefits shall be determined in accordance with the applicable sections of the Retirement Plan as in existence as of the effective date hereof, together with any increase in benefits occurring thereafter, as though the limitations of Section 401(a) (17) of the Code did not apply, and reduced by the benefits which are permitted to be paid under the Retirement Plan.

Such excess benefit shall be paid at the same time and in the same form as the Participant’s benefits under the applicable Retirement Plan.

Section 4.2 Benefit for Participants of the Plan and Excess Plan

In the event that any Participant is also a participant in the Excess Plan, this Plan shall pay such Participant a benefit in accordance with the Retirement Plan as in existence as of the effective date hereof, including the adjustment in the benefit under such Retirement Plan and any other increase in benefits occurring thereafter, as though the limitations of Sections 401(a) (17) and 415 of the Code did not apply, and reduced by the benefits which are permitted to be paid under the Retirement Plan. In such event, no payment of benefits shall be made under Article IV of the Excess Plan.

Section 4.3 Application of Article IV

This Article IV applies only to Participants other than those listed in Appendix I.

ARTICLE V

ADMINISTRATION

Section 5.1 The Committee To Be Named Fiduciary

(a) The Committee shall be the “Named Fiduciary” (within the meaning of ERISA) of the Plan with all responsibility for the operation and administration of the Plan. The Committee shall have the power to delegate specific fiduciary responsibilities of the Participating Employers to any person or group of persons, and such person or group may serve in more than one such delegated capacity. Such delegations must be accepted in writing and may be made to employees of the Participating Employers or Associated Companies or to other individuals, all of whom shall serve at the pleasure of the Committee, and if fulltime employees of the Participating Employers or Associated Employers, without compensation. Any such person may resign by delivering a written resignation to the Committee.

(b) The Committee shall supervise and review the activities of the Asset Manager and the Plan Administrator.

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Section 5.2 Asset Manager

(a) The Asset Manager shall be the person named as the Asset Manager for the Excess Plan and shall be the fiduciary in charge of the financial affairs of the Plan. The Asset Manager shall manage the assets, if any, in accordance with the terms of the Plan and shall have all powers necessary to carry out her duties. If at any time there shall be no Asset Manager or if the Asset Manager shall be unable to perform her duties, the President of the Company shall designate a person to serve as Asset Manager until the Board of Directors of the Company appoints a successor.

(b) The Asset Manager shall have the following specific duties and responsibilities in addition to any other duties specified in the Plan or by applicable law.

(1) The Asset Manager shall have responsibility for legal, actuarial, and accounting services provided to the Plan; may authorize an agent, to act on her behalf; and may contract for legal, actuarial, medical, accounting, clerical, and other services to carry out her duties and to discharge her responsibilities.

(2) The Asset Manager shall adopt from time to time actuarial tables and actuarial methods for use in all actuarial calculations, if any, required in connection with the determination of the funding status of the Plan. As an aid to the Asset Manager in connection therewith, the actuary consultant designated by the Asset Manager shall make annual actuarial valuations of the contingent assets and liabilities of the Plan, and shall certify to the Asset Manager the tables, actuarial methods, rates of contribution, and other pertinent data and information that such actuary would recommend for use by the Asset Manager.

(3) The Asset Manager shall be responsible for the maintenance of all financial records of the Plan.

(4) The Asset Manager shall be responsible for the preparation of all financial statements and reports relating to the Plan.

(5) The Asset Manager shall be the Plan’s agent for service of any notice of process authorized by law.

Section 5.3 Plan Administrator

(a) The Plan Administrator shall be the person named as the plan administrator for the Excess Plan and shall be the fiduciary in charge of administration of the Plan. The Plan

5

Administrator shall administer the Plan in accordance with its terms, and shall have all powers necessary to carry out his duties. If at any time there shall be no Plan Administrator or if the Plan Administrator shall be unable to perform his duties, the President of the Company shall designate a person to serve as Plan Administrator until the Board of Directors of the Company appoints a successor.

(b) The Plan Administrator shall have the following specific duties and responsibilities in addition to any other duties specified in the Plan or by applicable law.

(1) Subject to the limitations contained in this Plan, the Plan Administrator shall adopt rules for the administration of the Plan as he considers desirable, provided such rules do not conflict with the Plan.

(2) The Plan Administrator may authorize an agent, to act on his behalf, and may contract for legal, actuarial, medical, accounting, clerical, and other services to carry out the Plan and to discharge his responsibilities.

(3) Except as otherwise expressly provided herein, the Plan Administrator may interpret and construe the Plan, or reconcile inconsistencies to the extent necessary to effectuate the Plan, and such action shall be binding upon the persons.

(4) The Plan Administrator shall adopt from time to time actuarial tables and actuarial methods for use in all actuarial calculations, if any, required connection with the determination of benefit payments under the Plan. As an aid to the Plan Administrator in connection therewith, the actuary consultant designated by the Asset Manager shall, if needed, certify the Plan Administrator the tables, actuarial methods, rates of contribution, and other pertinent data and information that such actuary would recommend for use by the Plan Administrator.

(5) The Plan Administrator shall be responsible for the maintenance of all employee, Participant, and beneficiary records for the Plan. The Plan Administrator shall also be responsible for the maintenance of records, appropriate notifications, and filings in connection with the interest of all Participants or their spouses or contingent annuitants.

(6) The Plan Administrator shall be responsible for the filing and disclosure, if required, of the annual report on Form 5500, summary plan description, summary of material modifications, summary annual report, and other disclosure information regarding the provisions of the Plan or rights thereunder that must be provided to Participants and their beneficiaries under the Plan.

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Section 5.4 Expenses

The Participating Employers shall pay all expenses of administering the Plan. Such expenses shall include any expenses incurred by a Participating Employer, the Committee, the Asset Manager, or the Plan Administrator, including, but not limited to, the payment of professional fees of consultants.

ARTICLE VI

NO TRUST FUND

No separate trust fund shall be established in connection with this Plan. This Plan shall be unfunded and the benefits thereof paid as necessary from the general assets of the Participating employers.

ARTICLE VII

CLAIMS PROCEDURE

The procedure for claiming benefits under the Plan shall be as follows:

(a) The Plan Administrator shall determine the benefits due hereunder to a Participant, or the Participant’s spouse or contingent annuitant, but a person may file a claim for benefits by written notice to the Plan Administrator.

(b) If a claim is denied in whole or in part, the Plan Administrator shall give the claimant written notice of such denial within thirty (30) days of the filing of the claim. Such notice shall (i) specify the reason or reasons for the denial, (ii) refer to the pertinent Plan provisions on which the denial is based, (iii) describe any additional material or information necessary to perfect the claim and explain the need therefor, and (iv) explain the review procedure described in subparagraph (c) hereof.

(c) The claimant may then appeal the denial of the claim by filing written notice of such appeal with the Committee within ninety (90) days after receipt of the notice of denial. The claimant or any authorized representative may, before or after filing notice of appeal, review any documents pertinent to the claim and submit issues and comments in writing. The Committee shall render a decision on such appeal within thirty (30) days after receipt of the appeal (unless a longer period is requested by the claimant), and shall forthwith give written notice of such decision.

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ARTICLE VIII

AMENDMENT AND TERMINATION

Section 8.1 Amendment

(a) Subject to the provisions hereinafter set forth, the Company reserves the right to amend the Plan at any time, and (to the extent permitted by ERISA and the Code) give any such amendment retroactive effect.

(b) The Committee may approve any technical amendments to the Plan (i) necessary to comply with federal law and regulations thereunder or (ii) that do not have a substantial impact on the cost or terms of the Plan. All other amendments must be approved by the Board of Directors of the Company.

Section 8.2 Termination

The Plan is adopted with the expectation that it shall be continued indefinitely, but the continuation of the Plan is not assumed as a contractual obligation by any Participating Employer. Each Participating Employer reserves the right to terminate the Plan with respect to its participation at any time. If the Plan is terminated (in full or in part), the then accrued benefit under this Plan of each affected Participant shall become 100% vested.

ARTICLE IX

MISCELLANEOUS

Section 9.1 Right to Employment Or Retirement Income

(a) Nothing contained in the Plan shall be deemed to give any Participant a right to remain in the employ of the Participating Employers.

(b)(1) Nothing contained in the Plan shall be deemed to give any Participant, retired Participant, spouse, beneficiary or contingent annuitant any right or claim to any benefit except as expressly provided in the Plan.

     (2) Notwithstanding any other provision in this Plan, in the event the Company fails to fulfill its obligation to make payments to the Participant, his beneficiary, or any other person entitled to payments under the Plan, the Company shall be liable to such person for any attorney’s fees and other legal costs related to enforcing such person’s claim against the Company.

8

Section 9.2 Inalienability

No Participant or any person having or claiming to have any interest of any kind or character in or under this Plan shall have any right to sell, assign, transfer, convey, hypothecate, anticipate, or otherwise dispose of such interest, and such interest shall not be subject to any liabilities or obligations of, or any bankruptcy proceedings, claims of creditors, attachment, garnishment, execution, levy, or other legal process against such person or such person’s property.

Section 9.3 Facility Of Payment

If any Participant, retired Participant, or spouse or contingent annuitant eligible to receive payments under this Plan is, in the opinion of the Plan Administrator, legally, physically, or mentally incapable of personally receiving and receipting for any payment under this Plan, the Plan Administrator may direct payments in installments not to exceed the amount of monthly pension to which the Participant was otherwise entitled, to such other person, persons, or institutions who, in the opinion of the Plan Administrator, are then maintaining or having custody of such payee, until claims are made by a duly appointed guardian or other legal representative of such payee. Such payments shall constitute a full discharge of the liability of the Plan to the extent thereof.

Section 9.4 Construction of Plan

(a) The headings of articles and sections are included herein solely for the convenience of reference, and if there is any conflict between such headings and the text of this Plan, the text shall be controlling.

(b) To the extent not preempted by ERISA, the Plan shall be governed, construed, administered and regulated according to the laws of the State of Hawaii.

Section 9.5 Forms

All consents, elections, applications, designations, etc. required or permitted under the Plan must be made on forms prescribed and furnished by the Plan Administrator, and shall be recognized only if properly completed, executed, and returned to the Plan Administrator.

Section 9.6 Effective Date

This Plan shall be effective as of January 1, 1994.

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TO RECORD the adoption of this Plan, the undersigned have caused this document to be executed this 19th day of April, 1994, effective as of January 1, 1994.

HAWAIIAN ELECTRIC INDUSTRIES, INC.
By	/s/ Peter C. Lewis
	Its V.P.-Administration
By	/s/ Robert F. Clarke
	Its President & CEO

10

EX-10.9

HEI Exhibit 10.9

HAWAIIAN ELECTRIC INDUSTRIES, INC.

EXCESS BENEFIT PLAN

PROLOGUE

Effective as of January 1, 1994, the Hawaiian Electric Industries, Inc. Excess Benefit Plan (the “Plan”) is hereby amended and restated in its entirety. The Plan is intended to qualify as an “excess benefit plan” under Section 3(36) of the Employee Retirement Income Security Act of 1974 and is not intended to meet or be subject to the qualification requirements of the Internal Revenue Code of 1986, as amended.

ARTICLE I

DEFINITIONS

The following terms as used herein shall have the indicated meaning, unless a different meaning is clearly required by the context. Whenever appropriate, words used in the singular may include the plural and vice versa, and the masculine gender shall always include the feminine gender.

1.1 Associated Company means (i) a corporation (other than a Participating Employer) that is a member of the same controlled group of corporations (within the meaning of Section 1563(a) of the Code, determined without regard to Section 1563(a)(4) and (e)(3)(C) of the Code) as a Participating Employer, (ii) an entity (other than a Participating Employer) under common control (within the meaning of Section 414(c) of the Code) with a Participating Employer, or (iii) a member (other than a Participating Employer) of an affiliated service group (within the meaning of Section 414(m) of the Code) with a Participating Employer.

1.2 Asset Manager means the person designated to manage the assets of the Plan in accordance with Section 5.2.

1.3 Code means the Internal Revenue Code of 1986, as amended.

1.4 Committee means the Hawaiian Electric Industries, Inc. Pension Investment Committee appointed pursuant to resolution of the Board of Directors of the Company.

1.5 Company means Hawaiian Electric Industries, Inc.

1.6 ERISA means the Employee Retirement Income Security Act of 1974, as amended.

1.7 Excess Pay Plan means the Hawaiian Electric Industries, Inc. Excess Pay Supplemental Executive Retirement Plan.

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1.8 Participant means any person meeting the eligibility requirements of Article II hereof.

1.9 Participating Employer means the Company and/or any other corporation that is a member of the same controlled group of corporations (as defined in Section 415(b) of the Code) as the Company and to which participation in the Retirement Plan is extended, excluding the Hawaiian Insurance & Guaranty Company, Ltd.

1.10 Plan means this Hawaiian Electric Industries, Inc. Excess Benefit Plan.

1.11 Retirement Plan means, as to any Participant, means as to any Participant, whichever one of the following plans in which that individual is a participant: the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries, the American Savings Bank Retirement Plan, or the Hawaiian Tug & Barge Corp./Young Brothers, Limited Salaried Pension Plan.

1.12 Plan Administrator means the person designated to administer the Plan in accordance with Section 5.3.

1.13 SERP means the Hawaiian Electric Industries, Inc. Supplemental Executive Retirement Plan and the American Savings Bank Supplemental Executive Retirement Plan.

ARTICLE II

ELIGIBILITY

Each participant in the Retirement Plan shall be a Participant in this Plan, excluding any participant: (i) whose benefits are subject to collective bargaining; (ii) not employed by a Participating Employer; or (iii) who is also a participant in the SERP.

ARTICLE III

CONTRIBUTIONS

No contributions to this Plan from Participants shall be permitted or required.

ARTICLE IV

BENEFITS

This Plan shall provide to each Participant a supplemental benefit to ensure that the full benefits described in the applicable Retirement Plan as of December 31, 1982, including the adjustment in the benefit under such Retirement Plan, any other increase in benefits occurring thereafter, and that portion of the Retirement Plan benefit in excess of the limitations

3

imposed by Section 415 of the Code, are paid. Such excess benefits shall be determined in accordance with the applicable sections of the applicable Retirement Plan as in existence as of December 31, 1982, including the adjustment in the benefit under such Retirement Plan and any other increase in benefits occurring thereafter, as though the limitations of Section 415 of the Code did not apply, and reduced by the benefits which are permitted to be paid under the applicable Retirement Plan.

Such excess benefits shall be paid at the same time and in the same form as the Participant’s benefits under the applicable Retirement Plan.

In the event any Participant is also a participant in the Excess Pay Plan, no benefits shall be payable from this Plan; rather, any benefits payable to such Participant shall be subject to Section 4.2 of the Excess Pay Plan.

ARTICLE V

ADMINISTRATION

Section 5.1 The Committee To be Named Fiduciary

(a) The Committee shall be the “Named Fiduciary” (within the meaning of ERISA) of the Plan with all responsibility for the operation and administration of the Plan. The Committee shall have the power to delegate specific fiduciary responsibilities of the Participating Employers to any person or group of persons, and such person or group may serve in more than one such delegated capacity. Such delegations must be accepted in writing and may be made to employees of the Participating Employers or Associated Companies or to other individuals, all of whom shall serve at the pleasure of the Committee, and if full-time employees of the Participating Employers or Associated Employers, without compensation. Any such person may resign by delivering a written resignation to the Committee.

(b) The Committee shall supervise and review the activities of the Asset Manager and Plan Administrator.

Section 5.2 Asset Manager

(a) The Asset Manager shall be the person named from time to time by the Board of Directors of the Company and shall be the fiduciary in charge of the financial affairs of the Plan. The Asset Manager shall manage the assets, if any, in accordance with the terms of the Plan and shall have all powers necessary to carry out her duties. If at any time there shall be no Asset Manager or if the Asset Manager shall be unable to perform her duties, the President of the Company shall designate a person to serve as Asset Manager until the Board of Directors of the Company appoints a successor.

4

(b) The Asset Manager shall have the following specific duties and responsibilities in addition to any other duties specified in the Plan or by applicable law.

(1) The Asset Manager shall have responsibility for legal, actuarial, and accounting services provided to the Plan; may authorize an agent, to act on her behalf; and may contract for legal, actuarial, medical, accounting, clerical, and other services to carry out her duties and discharge her responsibilities.

(2) The Asset Manager shall adopt from time to time actuarial tables and actuarial methods for use in all actuarial calculations, if any, required in connection with the determination of the funding status of the Plan. As an aid to the Asset Manager in connection therewith, the actuary consultant designated by the Asset Manager shall make annual actuarial valuations of the contingent assets and liabilities of the Plan, and shall certify to the Asset Manager the tables, actuarial methods, rates of contribution, and other pertinent data and information that such actuary would recommend for use by the Asset Manager.

(3) The Asset Manager shall be responsible for the maintenance of all financial records of the Plan.

(4) The Asset Manager shall be responsible for the preparation of all financial statements and reports related to the Plan.

(5) The Asset Manager shall be the Plan’s agent for service of any notice of process authorized by law.

Section 5.3 Plan Administrator

(a) The Plan Administrator shall be the person named from time to time by the Board of Directors of the Company and shall be the fiduciary in charge of administration of the Plan. The Plan Administrator shall administer the Plan in accordance with its terms, and shall have all powers necessary to carry out his duties. If at any time there shall be no Plan Administrator or if the Plan Administrator shall be unable to perform his duties, the President of the Company shall designate a person to serve as Plan Administrator until the Board of Directors of the Company appoints a successor.

(b) The Plan Administrator shall have the following specific duties and responsibilities in addition to any other duties specified in the Plan or by applicable law.

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(1) Subject to the limitations contained in this Plan, the Plan Administrator shall adopt rules for the administration of the Plan as he considers desirable, provided such rules do not conflict with the Plan.

(2) The Plan Administrator may authorize and agent, to act on his behalf, and may contract for legal, actuarial , medical, accounting, clerical, and other services to carry out the Plan and to discharge his responsibilities.

(3) Except as otherwise expressly provided herein, the Plan Administrator may interpret and construe the Plan, or reconcile inconsistencies to the extent necessary to effectuate the Plan and such action shall be binding upon the persons.

(4) The Plan Administrator shall adopt from time to time actuarial tables and actuarial methods for use in all actuarial calculations, if any, required connection with the determination of benefit payments under the Plan. As an aid to the Plan Administrator in connection therewith, the actuary consultant designated by the Asset Manager shall, if needed, certify the Plan Administrator the tables, actuarial methods, rates of contribution, and other pertinent data and information that such actuary would recommend for use by the Plan Administrator.

(5) The Plan Administrator shall be responsible for the maintenance of all employee, Participant, and beneficiary records for the Plan. The Plan Administrator shall also be responsible for the maintenance of records, appropriate notifications, and filings in connection with the interest of all Participants of their spouses or contingent annuitants.

(6) The Plan Administrator shall be responsible for the filing and disclosure, if required, of annual report on Form 5500, summary plan description, summary of material modifications, summary annual report, and other disclosure information regarding the provisions of the Plan or rights thereunder that must be provided to Participants and their beneficiaries the Plan.

Section 5.4 Expenses

The Participating Employees shall pay all expenses of administering the Plan. Such expenses shall include any expenses incurred by a Participating Employer, the Committee, the Asset Manager, or the Plan Administrator, including but not limited to, the payment of professional fees of consultants.

ARTICLE VI

NO TRUST FUND

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No separate trust fund shall be established in connection with this Plan. This Plan shall be unfunded and the benefits thereof paid as necessary from the general assets of the Participating employers.

ARTICLE VII

CLAIMS PROCEDURE

The procedure for claiming benefits under the Plan shall be as follows:

(a) The Plan Administrator shall determine the benefits due hereunder to a Participant or a Participant’s spouse or contingent annuitant, but a person may file a claim for benefits by written notice to the Plan Administrator.

(b) If a claim is denied in whole or in part, the Plan Administrator shall give the claimant written notice of such denial within thirty (30) days of the filing of the claim. Such notice shall (i) specify the reason or reasons for the denial, (ii) refer to the pertinent Plan provisions on which the denial is based, (iii) describe any additional material or information necessary to perfect the claim and explain the need therefor, and (iv) explain the review procedure described in subparagraph (c) hereof.

(c) The claimant may then appeal the denial of the claim by filing written notice of such appeal with the Committee within ninety (90) days after receipt of the notice of denial. The claimant or any authorized representative may, before of after filing notice of appeal, review any documents pertinent to the claim and submit issues and comments in writing. The Committee shall render a decision on such appeal within thirty (30) days after receipt of the appeal (unless a longer period is requested by the claimant), and shall forthwith give written notice of such decision.

ARTICLE VIII

AMENDMENT AND TERMINATION

Section 8.1 Amendment

(a) Subject to the provisions hereinafter set forth, the Company reserves the right to amend the Plan at any time, and (to the extent permitted by ERISA and the Code) give any such amendment retroactive effect.

(b) The Committee may approve any technical amendments to the Plan (i) necessary to comply with federal law and regulations thereunder or (ii) that do not have substantial

7

impact on the cost or terms of the Plan. All other amendments must be approved by the Board of Directors of the Company.

Section 8.2 Termination

The Plan is adopted with the expectation that it shall be continued indefinitely, but the continuation of the Plan is not assumed to be a contractual obligation by any Participating Employer. Each Participating Employer reserves the right to terminate the Plan with respect to its participation at any time. If the Plan is terminated (in full or in part), then accrued benefit under this Plan of each affected Participant shall become 100% vested.

ARTICLE IX

MISCELLANEOUS

Section 9.1 Right to Employment Or Retirement Income

(a) Nothing contained in the Plan shall be deemed to give any Participant a right to remain in the employ of the Participating Employers.

(b) (1) Nothing contained in the Plan shall be deemed to give any Participant, retired Participant, spouse, beneficiary or contingent annuitant any right or claim to any benefit except as expressly provided in the Plan.

      (2) Notwithstanding any other provision in this Plan, in the event the Company fails to fulfill its obligation to make payments to the Participant, his beneficiary, or any other person entitled to payments under the Plan, the Company shall be liable to such person for any attorney’s fees and other legal costs related to enforcing such person’s claim against the Company.

Section 9.2 Inalienability

No Participant or any person having or claiming to have any interest of any kind or character in or under this Plan shall have any right to sell, assign, transfer, convey, hypothecate, anticipate, or otherwise dispose of such interest, and such interest shall not be subject to any liabilities or obligations of, or any bankruptcy proceedings, claims of creditors, attachment, garnishment, execution, levy, or other legal process against such person or such person’s property.

Section 9.3 Facility of Payment

If any Participant, retired Participant, or spouse or contingent annuitant eligible to receive payments under this Plan is, in the opinion of the Plan Administrator, legally, physically,

8

or mentally incapable of personally receiving and receipting for any payment under this Plan, the Plan Administrator may direct payments in installments not to exceed the amount of monthly pension to which the Participant was otherwise entitled, to such other person, persons, or institutions who, in the opinion of the Plan Administrator, are then maintaining of having custody of such payee, until claims are made by a duly appointed guardian or other legal representative of such payee. Such payments shall constitute a full discharge of the liability of the Plan to the extent thereof.

Section 9.4 Construction Of Plan

(a) The headings of articles and sections are included herein solely for the convenience of reference, and if there is any conflict between such headings and the text of this Plan, the text shall be controlling.

(b) To the extent not preempted by ERISA, the Plan shall be governed, construed, administered and regulated according to the laws of the State of Hawaii.

Section 9.5 Forms

All consents, elections, applications, designations, etc. required or permitted under the Plan must be made on forms prescribed and furnished by the Plan Administrator, and shall be recognized only if properly completed, executed, and returned to the Plan Administrator.

TO RECORD the adoption of this amended and restated form to the Plan, the undersigned have caused this document to be executed this 19^th day of April, 1994, effective as of January 1, 1994.

HAWAIIAN ELECTRIC INDUSTRIES, INC.
By	/s/ Peter C. Lewis
	Its V.P. - Administration
By	/s/ Robert F. Clarke
	Its President & CEO

9

EX-10.12

HEI Exhibit 10.12

HAWAIIAN ELECTRIC INDUSTRIES, INC.

1990 Nonemployee Director Stock Plan,

As Amended and Restated

1. Purposes of the Plan

The purposes of this Hawaiian Electric Industries, Inc. 1990 Nonemployee Director Stock Plan are to provide participating directors with additional incentives to improve the Company’s performance by increasing the level of stock owned by such nonemployee directors to reinforce the participating directors’ role in enhancing shareholder value, and to provide an additional means of attracting and retaining such nonemployee directors through the issuance of Common Stock under the Plan as compensation to Nonemployee Directors. As amended and restated herein, this Plan incorporates all amendments effective on or before May 1, 2002, including provisions formerly memorialized in the Hawaiian Electric Industries, Inc. 1999 Nonemployee Company Director Stock Grant Plan, which is hereby superceded.

2. Definitions

When used herein, the following terms shall have the respective meanings set forth below:

(a) “Annual Retainer” means the annual fee payable to all Nonemployee Company Directors and Nonemployee Participating Company Directors as provided in Section 6 below (exclusive of any expense reimbursements).

(b) “Annual Meeting of Shareholders” means the annual meeting of shareholders of the Company, or any Participating Company, at which directors of the Company or the Participating Company, as the case may be, are elected.

(c) “Board” means the Board of Directors of the Company.

(d) “Committee” means the HEI Management Committee or such other committee appointed from time to time by the Board to administer the Plan in accordance with Section 4(a) hereof.

(e) “Common Stock” means the common stock, without par value, of the Company.

(f) “Company” means Hawaiian Electric Industries, Inc., a Hawaii corporation, and any successor corporation.

(g) “Employee” means any officer or employee of the Company or any of its direct or indirect subsidiaries or affiliates (whether or not such subsidiary or affiliate participates in the Plan).

(h) “Nonemployee Company Director” means any person who is elected or appointed to the Board of Directors of the Company and who is not an employee.

(i) “Nonemployee Participating Company Director” means any person who is elected or appointed to the Board of Directors of any one or more Participating Companies and who is not an Employee.

(j) “Participating Company” means any direct or indirect subsidiary or affiliate of the Company whose participation in the Plan has been approved by the Board.

(k) “Plan” means the Company’s 1990 Nonemployee Director Stock Plan, as amended and restated as set forth herein, as it may be further amended from time to time.

(l) “Stock Payment” means the grant of shares of Common Stock to Nonemployee Company Directors or Nonemployee Participating Company Directors for services rendered as a director of the Company or a Participating Company, as provided in Section 7 hereof.

3. Shares of Common Stock Subject to the Plan

Subject to adjustment as provided in Section 9 below, the maximum aggregate number of shares of Common Stock that may be issued under the Plan, when taken together with any shares ever granted under the provisions of the Hawaiian Electric Industries, Inc. 1999 Nonemployee Company Director Stock Grant Plan, is 100,000 shares. The Common Stock to be issued under the Plan will be made available from authorized but unissued shares of Common Stock, and the Company shall set aside and reserve for issuance under the Plan said number of shares.

4. Administration of the Plan

(a) The Plan will be administered by the Committee, which will consist of three or more persons who are not eligible to participate in the Plan. Members of the Committee need not be members of the Board. The Company shall pay all costs of administration of the Plan.

(b) Subject to the express provisions of the Plan, the Committee has and may exercise such powers and authority of the Board as may be necessary or appropriate for the Committee to carry out its functions under the Plan. Without limiting the generality of the foregoing, the Committee shall have full power and authority (i) to determine all questions of fact that may arise under the Plan, (ii) to interpret the Plan and to make all other determinations necessary or advisable for the administration of the Plan, and (iii) to prescribe, amend, and rescind rules and regulations relating to the Plan, including, without limitation, any rules which the Committee determines are necessary or appropriate to ensure that the Company, each Participating Company and the Plan will be able to comply with all applicable provisions of any federal, state or local law, including securities laws and laws relating to the withholding of tax. All interpretations, determinations, and actions by the Committee will be final, conclusive, and binding upon

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all parties. Any action of the Committee with respect to the administration of the Plan shall be taken pursuant to a majority vote at a meeting of the Committee (at which members may participate by telephone) or by the unanimous written consent of its members.

(c) Neither the Company, nor any Participating Company, nor any representatives, employees or agents of the Company or any Participating Company, nor any member of the Board, the HEI Compensation Committee or the Committee or designee thereof will be liable for any damages resulting from any action or determination made by the Board, the HEI Compensation Committee or the Committee with respect to the Plan or any transaction arising under the Plan or any omission in connection with the Plan in the absence of willful misconduct or gross negligence.

5. Participation in the Plan

(a) All Nonemployee Company Directors and Nonemployee Participating Company Directors shall participate in the applicable provisions of the Plan, subject to the conditions and limitations of the Plan, so long as they remain eligible to participate in the Plan.

(b) Nonemployee Company Directors and Nonemployee Participating Company Directors shall be eligible for Annual Retainers pursuant to the terms of Section 6 of the Plan and for Stock Payments pursuant to the terms of Section 7 of the Plan.

6. Determination of Nonemployee Directors’ Annual Retainers

The Committee shall meet annually to determine the Annual Retainer for all Nonemployee Directors, subject to approval by the HEI Compensation Committee and the Board. Unless there are material changes in the duties of a Nonemployee Company Director or a Nonemployee Participating Company Director during the course of any calendar year, the Annual Retainer shall not be determined more than once each calendar year. The Annual Retainer shall be paid to each Nonemployee Company Director and each Nonemployee Participating Company Director by the respective company for which the person serves as a director. The Annual Retainer shall be paid at such times and in such manner as may be determined by the Board or the Committee.

7. Determination of Nonemployee Directors’ Stock Payments

(a) Each Nonemployee Company Director who serves in that capacity immediately following the date of the Annual Meeting of Stockholders of the Company shall receive, in addition to the Annual Retainer payable to such Nonemployee Company Director, a Stock Payment equal to six hundred (600) shares of Common Stock for serving as a Nonemployee Company Director (one thousand (1,000) shares in the case of the first Stock Payment to a Nonemployee Company Director pursuant to this sentence). Each Nonemployee Participating Company Director (who is not also a director of the Company) who serves in that capacity immediately following the date of the Annual Meeting of Stockholders of one or more Participating Companies shall receive, in

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addition to the Annual Retainer payable to such Nonemployee Participating Company Director, a Stock Payment equal to three hundred (300) shares of Common Stock for serving as a Nonemployee Participating Company Director. Each Director who during any calendar year thereafter becomes a Nonemployee Company Director or Nonemployee Participating Company Director for the first time (whether by election or appointment as a director of the Company or a Participating Company), shall receive, in addition to any Annual Retainer payable, a Stock Payment equal to one thousand (1,000) shares of Common Stock (in the case of the Company) or three hundred (300) shares of Common Stock (in the case of a Participating Company), for serving as a Nonemployee Company Director or Nonemployee Participating Company Director, as the case may be. Such Stock Payments shall be paid by the Company as soon as practicable following the date such director is first elected or appointed to the Board of Directors of the Company or the Board of Directors of a Participating Company, as the case may be.

(b) No Nonemployee Company Director or Nonemployee Participating Company Director shall be required to forfeit or otherwise return to the Company any shares of Common Stock issued to him or her as a Stock Payment pursuant to the Plan notwithstanding any change in status of such director which renders him or her ineligible to continue as a participant in the Plan.

8. Shareholder Rights

(a) Nonemployee Company Directors and Nonemployee Participating Company Directors shall not be deemed for any purpose to be or have rights as shareholders of the Company with respect to any shares of Common Stock except as and when such shares are issued and then only from the date of the certificate therefor. No adjustment shall be made for dividends or distributions or other rights for which the record date precedes the date of such stock certificate.

(b) Subject to the provisions of Section 8(a) above, Nonemployee Company Directors and Nonemployee Participating Company Directors will have all rights of a shareholder with respect to Common Stock issued, including the right to vote the shares and receive all dividends and other distributions paid or made with respect thereto.

9. Adjustment for Changes in Capitalization

If the outstanding shares of Common Stock of the Company are increased, decreased, or exchanged for a different number or kind of shares or other securities, or if additional shares or new or different shares or other securities are distributed with respect to such shares of Common Stock or other securities, through merger, consolidation, sale of all or substantially all of the property of the Company, reorganization, recapitalization, reclassification, stock dividend, stock split, reverse stock split, combination of shares, rights offering, distribution of assets or other distribution with respect to such shares of Common Stock or other securities or other change in the corporate structure or shares of Common Stock, the maximum number of shares and/or the kind of shares that may be issued under the Plan may be appropriately adjusted by the Committee. Any determination by the Committee as to any such adjustment will be final, binding, and

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conclusive. The maximum number of shares issuable under the Plan as a result of any such adjustment shall be rounded up to the nearest whole share.

10. Continuation of Director or Other Status

Nothing in the Plan or in any instrument executed pursuant to the Plan or any action taken pursuant to the Plan shall be construed as creating or constituting evidence of any agreement or understanding, express or implied, that the Company or any other Participating Company, as the case may be, will retain a Nonemployee Company Director or Nonemployee Participating Company Director as a director or in any other capacity for any period of time or at a particular retainer or other rate of compensation, as conferring upon any director any legal or other right to continue as a director or in any other capacity, or as limiting, interfering with or otherwise affecting the right of the Company or a Participating Company to terminate a director in his or her capacity as a director or otherwise at any time for any reason, with or without cause, and without regard to the effect that such termination might have upon him or her as a participant under the Plan.

11. Compliance with Government Regulations

Neither the Plan nor the Company shall be obligated to issue any shares of Common Stock pursuant to the Plan at any time unless and until all applicable requirements imposed by any federal and state securities and other laws, rules, and regulations, by any regulatory agencies or by any stock exchanges upon which the Common Stock may be listed have been fully met. As a condition precedent to any issuance of shares of Common Stock and delivery of certificates evidencing such shares pursuant to the Plan, the Board or the Committee may require a Nonemployee Company Director or Nonemployee Participating Company Director to take any such action and to make any such covenants, agreements and representations as the Board or the Committee, as the case may be, in its discretion deems necessary or advisable to ensure compliance with such requirements. The Company shall in no event be obligated to register the shares of Common Stock issued or issuable under the Plan pursuant to the Securities Act of 1933, as now or hereafter amended, or to qualify or register such shares under any securities laws of any state upon their issuance under the Plan or at any time thereafter, or to take any other action in order to cause the issuance and delivery of such shares under the Plan or any subsequent offer, sale or other transfer of such shares to comply with any such law, regulation or requirement. Nonemployee Company Directors and Nonemployee Participating Company Directors are responsible for complying with all applicable federal and state securities and other laws, rules and regulations in connection with any offer, sale or other transfer of the shares of Common Stock issued under the Plan or any interest therein including, without limitation, compliance with the registration requirements of the Securities Act of 1933, as amended (unless an exemption therefrom is available), or with the provisions of Rule 144 promulgated thereunder, if available, or any successor provisions.

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12. Nontransferability of Rights

No Nonemployee Company Director or Nonemployee Participating Company Director shall have the right to assign the right to receive any Stock Payment or any other right or interest under the Plan, contingent or otherwise, or to cause or permit any encumbrance, pledge or charge of any nature to be imposed on any such payment (prior to the issuance of stock certificates evidencing such Stock Payment) or any such right or interest.

13. Amendment and Termination of Plan

(a) The Board will have the power in its discretion, to amend, suspend or terminate the Plan at any time. No such amendment will, without approval of the shareholders of the Company:

(i) Change the class of persons eligible to receive Stock Payments under the Plan or otherwise modify the requirements as to eligibility for participation in the Plan; or

(ii) Increase the number of shares of Common Stock which may be issued under the Plan (except for adjustments as provided in Section 9 hereof).

(b) No amendment, suspension or termination of the Plan will, without the consent of the Nonemployee Company Director or Nonemployee Participating Company Director, alter, terminate, impair, or adversely affect any right or obligations under any Stock Payment previously granted under the Plan to such Participant, unless such amendment, suspension or termination is required by applicable law.

(c) Notwithstanding the foregoing, the Board may, without further action by the shareholders of the Company, amend the Plan or modify Stock Payments under the Plan (i) in response to changes in securities or other laws, or rules, regulations or regulatory interpretations thereof, applicable to the Plan, or (ii) to comply with stock exchange rules or requirements.

14. Governing Law

The laws of the State of Hawaii shall govern and control the interpretation and application of the terms of the Plan.

15. Effective Date and Duration of the Plan

The Plan, as amended and restated herein, will become effective as of May 1, 2002. Unless previously terminated by the Board, the Plan will terminate on April 27, 2010.

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EX-10.15

HEI Exhibit 10.15

EMPLOYMENT SEPARATION AGREEMENT

This Agreement by and between ROBERT F. MOUGEOT (“Employee”) and HAWAIIAN ELECTRIC INDUSTRIES (“HEI”), and its subsidiary and affiliated entities and the shareholders, directors, officers, employees and agents of HEI and its subsidiary and affiliated entities (collectively referred to as “Employer”) is effective as of the date described in Section 7 below and sets forth the rights and obligations of the parties arising from Employee’s recruitment for, employment with, and separation from employment with Employer as of the date of the last signatory to this Agreement.

1. Separation from Employment

Employee hereby retires from employment with Employer effective as of midnight, November 12, 2002. Employee shall be paid all salary then due plus all earned and accrued employee benefits less any applicable payroll taxes in accordance with the terms and conditions of the Employer’s policies and plans governing such employee benefits. Employee shall not be required to perform any employment duties for Employer after November 12, 2002, and shall not receive, earn or be entitled to any wages, employee benefits or other compensation from Employer from and after November 12, 2002, except as provided in the Employer’s employee benefits policies and plans or as provided in Section 2 below.

2. Additional Separation Benefits

Subject to the provisions of Section 7 below and in consideration of Employee’s execution of this Agreement and his full and timely performance of all his promises and obligations in this Agreement, Employer agrees to provide Employee the following additional severance benefits upon the execution of this Agreement by Employee and the expiration of the

seven (7) day revocation period described in Section 7 below.

a. Except as otherwise provided in Section 7 below, which shall supersede anything stated herein to the contrary, a severance payment in the amount of Three Hundred Fifty Thousand and No/1000 Dollars ($350,000.00), less applicable payroll taxes payable as follows:

(1) Seventy-Five Thousand and No/100 Dollars ($75,000.00), less applicable payroll taxes, upon expiration of the seven (7) day recission period described in Section 7 below;

(2) One Hundred Thousand and No/100 Dollars ($100,000.00), less applicable payroll taxes, on or before January 3, 2003; and

(3) One Hundred Seventy-Five Thousand and No/100 Dollars ($175,000.00), less applicable payroll taxes, on or before January 5, 2004.

b. Employee will be entitled to participate in the 2002 Executive Incentive Compensation Plan (“EICP) with no pro-rata adjustment for retiring prior to December 31, 2002. In addition, if the earnings threshold is met for the 2002 EICP, Employee will receive a payout at the “Target” level for the goal “Overall performance evaluation by the President,” weighted at 30 percent of Employee’s 2002 EICP. Employee will also be entitled to participate in the 2000-2002 Long-Term Incentive Plan (“LTIP”), 2001-2003 LTIP and the 2002-2004 LTIP with no pro-rata adjustment for retiring prior to December 31, 2002; provided, however, that if there is a payout for the HEI officers under the 2001-2003 LTIP and the 2002-2004 LTIP, Employee will be eligible for a 24/36 payout and a 12/36 payout, respectively. Effective upon the date of Employee’s retirement, all outstanding non-qualified stock option (“NQSO”) grants already made to Employee

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(1999, 2000, 2001 and 2002 grants) will become fully exercisable, notwithstanding that the option may not be otherwise fully exercisable under Section 3.1 (a) of Employee’s Non-qualified Stock Option Agreement. In addition, upon Employee’s exercise of each NQSO stock option, Employee will be entitled to receive all dividend equivalent awards on Employee’s outstanding NQSO grants up to and including dividend equivalent awards made on November 12, 2002.

c. As a retiree of HEI, Employee will be eligible to receive retirement benefits generally available to other HEI retirees under The Postretirement Welfare Benefits Plan for Employees of Hawaiian Electric Company, Inc. and Participating Employers.

d. In consideration of Employer’s agreement to provide severance payments described in paragraph 2.a above, Employee agrees that such payments shall constitute voluntary prepayment of unemployment compensation benefits and/or workers’ compensation benefits under Hawaii Revised Statutes Section 386-52 if Employee is awarded any unemployment or workers’ compensation benefits attributable to his employment or termination of employment with Employer. Employee further agrees to meet in Honolulu, Hawaii, with legal counsel representing American Savings Bank (“ASB”) in the American Savings Bank, F.S.B. v. Paine Webber, Inc. litigation to prepare for his testimony in that litigation and to be available during the trial, including mediation or arbitration, of the case to testify in good faith on behalf of ASB. The parties estimate that Employee’s preparation time should not exceed one (1) day and that his time testifying should not exceed one (1) day, although Employee’s availability to testify may require more than one (1) day if the Court is not able to assign a specific day in

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advance for Employee’s testimony.

3. Employer Property

Employee shall promptly return to Employer any remaining Employer information and property still in Employee’s possession or control including and without limitation confidential business or customer reports, maps, files, memoranda, records, software, credit cards, door and file keys, computer access codes, disks and instruction manuals, and any other property which Employee received or prepared or helped prepare in connection with employee’s employment with Employer.

4. Confidentiality and Cooperation

Employee and Employer agree that they will cooperate with each other to assure a harmonious and positive separation, and neither party will make any disparaging comments about Employee, Employer, its directors, officers, financial operations or reports. As part of such cooperation, Employee agrees to Employer’s prior public statement of Employee’s retirement. Employee and Employer agree to keep the terms, amount and fact of this Agreement completely confidential. However, Employee may discuss this Agreement with his attorney, accountant and immediate family; provided, they agree to keep the contents of this Agreement confidential and not disclose it to others. Employer may likewise disclose the terms, amount or facts of this Agreement to those directors, officers, employees, attorneys, auditors, accountants, government rating agencies or other private entities as necessary or prudent for its business operations. Employee also agrees that any and all information obtained by Employee or disclosed to Employee during his employment with the Employer which is not already known to the general public, including but not limited to Employer’s financial and business information, strategic plans, projects, customers, programs, methods of operation, processes, practices,

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policies and procedures, are strictly confidential and proprietary to Employer, and shall be treated as trade secrets of Employer. Employee covenants in perpetuity that such trade secrets shall not be disclosed, discussed, or revealed to any persons, entities or organizations by Employee at any time. Employee understands and acknowledges that the existence of this confidentiality provision is a material inducement for Employer to enter into this Agreement. The parties agree that Employer would suffer irreparable harm if Employee breaches this confidentiality provision, and, therefore, both parties agree that if such breach occurs, then in addition to any other remedies available to Employer at law or equity Employee shall immediately repay Employer as a reasonable estimate of damages and not as a penalty an amount up to twenty-five percent (25%) of the severance payment described in Section 2.a above plus interest at the maximum rate allowed by law from the date of payment of the severance payment until repaid by Employee and no further payments will be made under Section 2.

5. Voluntary Agreement

Employee fully understands his right to discuss and has had the opportunity to discuss all aspects of this Agreement with Employee’s family or attorney and represents to Employer that Employee has carefully read and fully understands all of the provisions of this Agreement and that he is voluntarily entering into this Agreement.

6. Release, Indemnification and Promise Not To Sue.

a. Release. As a material inducement to Employer to enter into this Agreement and to provide to Employee the additional separation benefits described in Section 2 above, Employee hereby irrevocably and unconditionally releases, acquits and forever discharges Employer from any and all claims, liabilities, and expenses (including attorneys’ fees and costs actually incurred) of any nature whatsoever, statutory or

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common law, known or unknown, suspected or unsuspected (including, but not limited to any claims arising out of or under any (i) contract of employment; (ii) federal, state or local laws prohibiting age or other forms of employment discrimination; (iii) Employee’s recruitment for employment with or separation from employment with Employer; and, (iv) employee benefit plan or law) which Employee now has, owns or holds, or claims to have, own or hold, or which Employee at any time heretofore had, owned or held, or claimed to have, own or hold against Employer based on any act or omission occurring up to the termination of Employee’s employment with Employer (hereafter collectively called “Claims”). The foregoing release shall not apply to any claim by Employee to enforce Employer’s express obligations under this Agreement or for benefits under any federal or Hawaii law that cannot be waived or discharged by agreement.

b. Indemnification.

As a further material inducement to Employer to enter into this Agreement and to pay to employee the separation benefits described in Section 2 above, Employee hereby agrees to indemnify and hold Employer harmless from and against any and all losses, costs, damages, or expenses, including, without limitation, attorneys’ fees incurred by Employer arising out of any breach of this Agreement by Employee and not to initiate or file any claim or lawsuit over any Claim released above. Employee expressly understands and acknowledges that this Agreement may be pleaded as a defense to, and may be used as the basis for an attempted injunction against any action, suit, administrative or other proceeding which may be instituted, prosecuted or attempted as a result of an alleged breach of this Agreement by Employee.

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c. Promise Not To Sue.

Employee also agrees not to file or initiate any claim or lawsuit with any agency or court based on any claim covered by the foregoing release, including any claim arising out of employee’s employment or separation from employment with Employer other than to enforce this Agreement. If Employee files any administrative claim or lawsuits against Employer based on any claim arising out of his employment or termination of employment with Employer, then in addition to all other remedies provided by law or equity, Employee agrees to pay Employer for all costs, including reasonable attorneys fees, incurred by Employer in defending against administrative claims or lawsuit and to credit any amounts paid under this Agreement against any recovery obtained by Employee.

7. Review and Revocation Rights.

EMPLOYEE UNDERSTANDS AND ACKNOWLEDGES THAT HE HAS UP TO TWENTY-ONE (21) DAYS TO DECIDE WHETHER TO SIGN THIS AGREEMENT AND SHOULD CONSULT WITH AN ATTORNEY. WITHIN SEVEN (7) DAYS AFTER SIGNING THIS AGREEMENT, EMPLOYEE MAY RESCIND IN WRITING ONLY EMPLOYEE’S RELEASE OF ANY CLAIMS UNDER THE FEDERAL AGE DISCRIMINATION IN EMPLOYMENT ACT (THE “ADEA”). IF THE SEVENTH DAY FALLS ON A SATURDAY, SUNDAY, OR HOLIDAY, THE NEXT REGULAR BUSINESS DAY WILL BE CONSIDERED THE SEVENTH DAY. IF EMPLOYEE ELECTS IN A TIMELY MANNER TO RESCIND THE RELEASE OF ANY FEDERAL ADEA CLAIM, THE RELEASE WILL STILL REMAIN IN EFFECT FOR ALL OTHER CLAIMS AND THE ADDITIONAL TERMINATION PAY AND BENEFITS

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DESCRIBED IN PARAGRAPH 2 ABOVE SHALL BE MODIFIED BY REDUCING THE SEVERANCE PAYMENT IN SECTION 2.a TO A TOTAL OFSEVENTY-FIVE THOUSAND AND NO/100 DOLLARS ($75,000.00).

EMPLOYEE UNDERSTANDS AND AGREES THAT UNLESS OTHERWISE AGREED IN WRITING BY THE PARTIES, THE TERMS OF THIS AGREEMENT WILL NOT BE EFFECTIVE UNTIL THE LATER OF THE TERMINATION OF EMPLOYEE’S EMPLOYMENT WITH EMPLOYER OR THE EXPIRATION OF THE SEVEN (7) DAY REVOCATION PERIOD DESCRIBED ABOVE. IF EMPLOYER EXECUTES AND DELIVERS THIS AGREEMENT BUT THEN TIMELY REVOKES HIS RELEASE OF ANY FEDERAL AGE DISCRIMINATION CLAIM, THIS AGREEMENT AND RELEASE OF ALL OTHER CLAIMS WILL REMAIN IN FULL FORCE AND EFFECT.

8. Arbitration.

Because of the delay, expense and publicity which results from the use of the State and Federal court systems, Employer and Employee agree to submit to final and binding arbitration any claims and disputes arising out of or related to this Agreement and Employee’s recruitment, employment, compensation, benefits, or termination of employment, including but not limited to all claims and disputes arising under Hawaii and Federal wrongful termination and employment discrimination laws (e.g. Title VII, ADEA, ADA, FMLA, or other anti-discrimination laws) rather than to use such court systems. In any such arbitration, the then existing American Arbitration Association rules for resolving employment disputes shall govern the arbitration, subject to the Federal Arbitration Act, if applicable, or if not applicable then the Hawaii Arbitration Act, HRS Chapter 658 then in effect.

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9. Mutual Agreement

The parties each represent and acknowledge that they are entering into this Agreement to effect an amicable and positive separation of Employee’s employment with Employer and not as an admission that either party has violated any law, or other legal obligations such as those described in paragraph 6 above. This Agreement represents an amicable compromise and settlement of all of Employee’s rights, claims and benefits.

10. Entire Agreement

Employee represents and acknowledges that in executing this Agreement he does not rely, and has not relied, upon any representation or statement by Employer not set forth in this Agreement regarding this agreement or employee’s recruitment for, employment with, or separation from employment with Employer.

This Employment Separation Agreement sets forth the entire agreement between Employer and employee with regard to the conditions of Employee’s separation and retirement from employment with Employer. Employee understands that this Agreement supersedes any and all prior agreements or understandings between the parties regarding Employee’s recruitment for, employment with and separation or retirement from employment with employer. This Agreement shall be binding upon and inure to the benefit of the parties, their successors and assigns.

Employee agrees to keep employer informed of his address to ensure Employee’s receipt of all mailings, such as W-2s, etc.

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PLEASE READ CAREFULLY. THIS EMPLOYMENT SEPARATION AGREEMENT INCLUDES A RELEASE OF ALL CLAIMS.

EMPLOYEE		EMPLOYER
		HAWAIIAN ELECTRIC INDUSTRIES, INC.
	/s/ Robert F. Mougeot	By:	/s/ Robert F. Clarke
	ROBERT F. MOUGEOT		ROBERT F. CLARKE
			Its Chief Executive Officer
Date:	November 17, 2002	Date:	November 17, 2002

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EX-10.16

HEI Exhibit 10.16

EXECUTIVE DEATH BENEFIT PLAN

OF

HAWAIIAN ELECTRIC INDUSTRIES, INC.

AND PARTICIPATING SUBSIDIARIES

I. ESTABLISHMENT OF PLAN

Hawaiian Electric Industries, Inc. (“HEI”) hereby establishes this Executive Death Benefit Plan of Hawaiian Electric Industries, Inc. and Participating Subsidiaries effective September 1, 2001. The only benefits provided under this Plan are death benefits. The Plan is an unfunded welfare plan maintained for the purpose of providing benefits for a select group of management employees of HEI and certain of its subsidiaries, as described in section 2520.104-24 of the regulations promulgated by the Secretary of Labor pursuant to the Employee Retirement Income Security Act of 1974, as amended.

II. DEFINITIONS

2.1. “Administrative Committee” means the Administrative Committee for the HEI Executive Death Benefit Plan, which shall be a three-person committee composed of the Vice President-Administration of HEI, the Vice President-Corporate Excellence of HECO, and the Manager-Compensation and Benefits of HECO (or the holders of any successor positions, however designated), and shall have the powers and duties set forth herein.

2.2. “Beneficiary” means the beneficiary designated in writing by a Participant. The Beneficiary designation must be made on a form provided by the Administrative Committee. A Participant must designate his or her Beneficiary at the time he or she becomes a Participant, and may change the designated Beneficiary at any time thereafter by executing a new Beneficiary designation. If the designated Beneficiary does not survive the Participant, or if there is no valid Beneficiary designation at the time of the Participant’s death, any benefits payable hereunder shall be paid to the Participant’s estate.

2.3. “Disabled” or “Disability” refers to the existence of a disability within the meaning of the long-term disability program maintained by the Participating Employer by whom a Participant is employed.

2.4. “Eligible Position” means a management position that is designated in the personnel records of the Participating Employer as:

a. Manager or above at HEI, HECO, MECO, or HELCO, Grade 50 and above at HEI; or

b. President and CEO at ASB.

2.5. “ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

2.6. “Participant” means a management employee or former employee of a Participating Employer who has satisfied the eligibility requirements of the Plan, as set forth in Article III below, and has not terminated employment or changed his or her position in a manner that results in a loss of eligibility to participate.

2.7. “Participating Employer” means HEI or one of the following HEI subsidiaries: Hawaiian Electric Company, Inc. (“HECO”); Maui Electric Company, Limited (“MECO”); Hawaii Electric Light Company, Inc. (“HELCO”); and American Savings Bank, F.S.B. (“ASB”).

2.8. “Plan” means the Executive Death Benefit Plan of Hawaiian Electric Industries, Inc. and Participating Subsidiaries, as set forth in this document and as amended from time to time.

2.9. “Retire” or “Retirement” means termination of employment with a Participating Employer after the Participant has qualified for immediate commencement of normal or early retirement benefits under the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries or the American Savings Bank Retirement Plan (whether or not such Participant actually elects to have such retirement benefits commence immediately).

2.10. “Salary” means base annual rate of salary, including any elective contributions to the Hawaiian Electric Industries Retirement Savings Plan, the Hawaiian Electric Industries, Inc. FlexPlan, the ASB Cafeteria Plan, or any successor plan thereof, but excluding any incentive compensation, bonuses, deferred compensation, fringe benefits, or other amount not included in base annual salary. Amounts paid under the Merit Performance Bonus Plan of ASB are not included in Salary, regardless of whether the Participant elects to contribute such amounts to the Hawaiian Electric Industries Retirement Savings Plan.

III. ELIGIBILITY

3.1. Becoming a Participant. To become a Participant in the Plan, a person must:

a. Be employed by a Participating Employer in an Eligible Position on or after the effective date of this Plan, or have been employed in an Eligible Position at ASB on or after January 1, 2001; and

b. Be designated as a Participant in writing by the Administrative Committee, or by a member of the Administrative Committee to whom the Committee has delegated the authority to designate Participants.

3.2. Forfeiture Upon Termination of Employment. A Participant who terminates employment with the Participating Employers for any reason other than Retirement, death, or Disability shall cease to be a Participant and shall forfeit any and all rights to benefits under this Plan.

3.3 Forfeiture Upon Transfer to Ineligible Position. A Participant who transfers to a position that is not an Eligible Position shall cease to be a Participant and shall forfeit any and all rights to benefits under this Plan.

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IV. BENEFITS

4.1. Benefits for HEI, HECO, MECO, and HELCO Participants. A Participant who is employed in, who Retired from, or who terminated employment due to Disability from, an Eligible Position with HEI, HECO, MECO, or HELCO, shall receive the following benefits:

a. If the Participant dies while actively employed, the Participant’s Beneficiary shall receive a lump sum death benefit equal to (i) two times the Participant’s Salary at the date of his or her death, (ii) divided by one minus the highest marginal rate of federal income tax imposed on benefits of this type as of the date of the Participant’s death.

b. If the Participant dies after he or she Retires, the Participant’s Beneficiary shall receive a lump sum death benefit equal to (i) one times the Participant’s Salary at the date of his or her Retirement, (ii) divided by one minus the highest marginal rate of federal income tax imposed on benefits of this type as of the date of the Participant’s death.

c. If the Participant incurs a Disability, then:

i. If the Participant dies while still Disabled and before attaining age 65, the Participant’s Beneficiary shall receive a lump sum death benefit equal to (i) two times the Participant’s Salary at the date he or she became Disabled, (ii) divided by one minus the highest marginal rate of federal income tax imposed on benefits of this type as of the date of the Participant’s death.

ii. If the Participant continues to be Disabled until the time he or she attains age 65, then upon the Participant’s death after such time the Participant’s Beneficiary shall receive a lump sum death benefit equal to (i) one times the Participant’s Salary at the date he or she became Disabled, (ii) divided by one minus the highest marginal rate of federal income tax imposed on benefits of this type as of the date of the Participant’s death.

4.2. Benefits for ASB Participants. If a Participant dies after he or she Retires from an Eligible Position with ASB, the Participant’s Beneficiary shall receive a lump sum death benefit equal to (i) one times the Participant’s Salary at the date of his or her Retirement, (ii) divided by one minus the highest marginal rate of federal income tax imposed on benefits of this type as of the date of the Participant’s death. A Participant who is employed in an Eligible Position with ASB shall not be entitled to any benefits hereunder if he or she dies, becomes Disabled, or otherwise terminates employment before he or she Retires.

4.3. Transfers Between ASB and Other Participating Employers. If a Participant transfers from an Eligible Position with ASB to an Eligible Position with another Participating Employer, or vice versa, the Participant’s entitlement to benefits shall be determined based on the Eligible Position in which he or she is last employed.

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4.4. Payment. All benefits payable under this Plan shall be paid by the Participating Employer by which the Participant was last employed.

4.5. Vesting. A Participant shall have a vested right to benefits under this Plan upon Retirement. Prior to Retirement, any benefit hereunder shall be subject to forfeiture in accordance with Section 3.2 or Section 3.3; provided, however, that no Participant’s right to benefits may be reduced or eliminated except in accordance with Section 3.2 or Section 3.3 or with the written consent of such Participant.

4.6. Claims Procedure. If any Participant or Beneficiary believes he or she is entitled to a benefit from the Plan which is different from the benefit initially determined, such Participant or Beneficiary may file a written claim for benefits with the Manager-Compensation and Benefits of HECO (or the holder of any successor position, however designated) (the “Manager”). The Manager shall consider such written claim and render a decision within ninety (90) days following receipt thereof. If the Manager denies any part of the claim, he or she shall provide the claimant with written notice of the denial and of the claimant’s right to a further review. The notice shall set forth, in a manner calculated to be understood by the claimant, the reason for the denial and shall refer to specific Plan provisions on which the denial is based and provide a description and explanation of additional information which the claimant might provide to perfect the claim.

Within ninety (90) days after receiving notice that a claim has been denied, the claimant may file a written appeal with the full Administrative Committee. The claimant may submit written comments, documents, records, and other information relating to the claim. Upon request, the claimant may obtain, free of charge, reasonable access to, and copies of, documents, records, and other information relevant to the claim. The Administrative Committee may require the claimant to provide such additional information or testimony as the Administrative Committee, in its sole discretion, deems useful or appropriate to its consideration of the claim. In reviewing the claim, the Administrative Committee shall take into account all comments, documents, records, and other information submitted by the claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination. The Administrative Committee shall render its final decision within sixty (60) days of receipt of the request for reconsideration unless special circumstances require an extension of time. If such an extension is required, the Administrative Committee shall provide the claimant with written notice of the extension within the initial sixty (60) day period, and the Administrative Committee shall render its decision as soon as possible but in no event later than one hundred twenty (120) days following receipt of the appeal. If the Administrative Committee’s final decision is a denial of the claim, the Administrative Committee shall provide written notice of the denial, which notice shall set forth, in a manner calculated to be understood by the claimant, the reason for the denial and shall refer to specific Plan provisions on which the denial is based.

Claim determinations by the Manager and the Administrative Committee shall be made in their discretion, as provided in Section 5.1. The final decision of the Administrative Committee shall be binding and conclusive on all persons.

If the Manager or Administrative Committee fails to respond to a claimant within the time limits set forth in this Section, the claimant may consider the claim denied and may pursue whatever

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additional remedies are available to it. A claimant must comply with these procedures and exhaust all possibilities contained herein before seeking relief in any other forum.

V. ADMINISTRATION

5.1. Administrative Committee’s Powers and Discretion. The Administrative Committee shall have the power to interpret and construe the provisions of the Plan, to resolve any ambiguities and reconcile any inconsistencies in its provisions, and to decide all questions of fact that arise in the operation of the Plan. All such powers shall be exercised in the Administrative Committee’s discretion. Specifically, but without limiting the generality of the foregoing, the Administrative Committee shall determine, in its discretion, all questions with respect to any individual’s rights under the Plan, including, but not limited to, eligibility for participation, eligibility for and the amount of benefits payable from the Plan, the validity and effect of any Beneficiary designation hereunder, and the proper Beneficiary to whom any benefits hereunder will be paid. The Administrative Committee, acting unanimously, shall also have the power to waive the application of Section 3.3 to a Participant if extenuating circumstances exist. The decision of the Administrative Committee with regard to the interpretation or construction of the Plan, or on any other matter within its authority, shall be binding and conclusive upon the Participating Employers and upon each Participant, Beneficiary, and any other interested party.

5.2. Delegation. The Administrative Committee may delegate authority to one or more of its members, or to any other employee of a Participating Employer, in its discretion. In particular, the Administrative Committee may delegate authority for the day-to-day administration of the Plan to the Manager-Compensation and Benefits of HECO or such persons in the HECO Benefits Department as such Manager may designate.

VI. MISCELLANEOUS

6.1. Effect on Prior Deferred Compensation Agreements. This Plan supersedes certain Deferred Compensation Agreements between Participants herein and HEI regarding the payment of death benefits similar to those provided hereunder. Such Deferred Compensation Agreements shall be of no further force or effect. As a condition of participation in this Plan, each Participant who was previously a party to such an agreement shall execute a written revocation of such agreement in a form provided by the Administrative Committee. This Plan does not affect Deferred Compensation Agreements that are currently in force between HEI and individuals who do not become Participants in this Plan, including retirees, disabled persons, and certain active employees of the Participating Employers who are not currently employed in Eligible Positions but who were previously employed in such positions and have been permitted to retain the benefit of Deferred Compensation Agreements.

6.2. Amendment and Termination. The Administrative Committee may amend or terminate the Plan at any time in its discretion; provided, however, that no amendment or termination of the Plan shall reduce the rights and benefits of any person who is a Participant at the time of the amendment or termination without such Participant’s written consent. No amendment or termination of the Plan shall affect benefits that have vested in accordance with Section 4.5.

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6.3. No Funding. Benefits shall be paid as needed solely from the general assets of the Participating Employers, insurance contracts whose premiums are paid directly by the Participating Employers from their general assets, or a combination thereof. This Plan shall constitute solely an unsecured promise by the Participating Employers to pay the benefits described herein. Participants and Beneficiaries shall rely solely upon such unsecured promise, and shall have no right, title, interest, or claim to any specific asset, fund, reserve, account, insurance policy, or other property of any nature.

6.4. Life Insurance Policies. The Administrative Committee, in its absolute discretion, may purchase or maintain life insurance contracts to assist in meeting the Participating Employers’ benefit obligations hereunder. Any such policies shall be the property of HEI or the Participating Employer purchasing and maintaining such policies. The Administrative Committee shall have the exclusive and unrestricted right to make any elections, exercise any rights, and receive and use any benefits payable thereunder. No Participant or Beneficiary shall have any interest in any such policy or any rights thereunder.

6.5. Nonalienation. No benefit payable under this Plan shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, encumbrance, or charge, and any attempt to do so shall be void; nor shall any such benefit be in any manner liable for or subject to the debts, contracts, liabilities, engagements, or torts of, or claims against, any Participant or Beneficiary.

6.6. No Right to Employment. Nothing in this Plan shall give any Participant any right to continued employment with any Participating Employer or limit in any way the Participating Employers’ right to discharge any Participant.

6.7. Indemnification. The Participating Employers shall indemnify and hold harmless their respective directors, officers, employees, and agents, including, without limitation, the members of the Administrative Committee, against any and all claims, losses, damages, expenses, and liabilities arising, directly or indirectly, from their responsibilities in connection with the Plan, and from the defense costs thereof (including reasonable attorneys’ fees), to the extent permitted by law and except where any such liability is judicially determined to be the result of gross negligence or willful misconduct. The right of indemnity shall be conditioned upon (1) timely notice to HEI of any claim asserted against a person within the scope of this Section, and (2) the indemnified person’s reasonable cooperation and assistance in the defense of such claim.

6.8. Costs of Enforcement. If the Administrative Committee denies a claim for benefits under this Plan, and the claimant is later determined to be entitled to such benefits, then in addition to such benefits the claimant shall be entitled to recover all costs of enforcing his or her claim, including, without limitation, attorneys’ fees and other legal costs.

6.9. Governing Law. This Plan shall be governed by, and construed and enforced in accordance with, the laws of the State of Hawaii, to the extent such laws are not preempted by ERISA.

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TO RECORD the adoption of this Plan, the undersigned have executed this document this 24^th day of August, 2001.

HAWAIIAN ELECTRIC INDUSTRIES, INC.
By	\s\ Robert F. Clarke
	Its Chairman, President & Chief Executive Officer
By	\s\ Peter C. Lewis
	Its Vice President – Administration & Corporate Secretary

ADOPTED AND APPROVED BY THE PARTICIPATING EMPLOYERS:
HAWAIIAN ELECTRIC COMPANY, INC.		AMERICAN SAVINGS BANK, F.S.B.
By	\s\ T. Michael May	By	\s\ Constance H. Lau
	Its President & Chief Executive Officer		Its President & Chief Executive Officer
MAUI ELECTRIC COMPANY, LIMITED		HAWAII ELECTRIC LIGHT COMPANY, INC.
By	\s\ Edward L. Reinhardt	By	\s\ Warren H.W. Lee
	Its President		Its President

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EX-13.1

HEI Exhibit 13.1

Hawaiian Electric Industries, Inc.

2002 Annual Report to Stockholders

Contents
2	Forward-Looking Statements
3	Selected Financial Data
4	Management’s Discussion and Analysis of Financial Condition and Results of Operations
31	Quantitative and Qualitative Disclosures about Market Risk
37	Independent Auditors’ Report
38	Consolidated Financial Statements
79	Directors and Executive Officers
80	Stockholder Information

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Forward-Looking Statements

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

• the effects of weather and natural disasters;

• the effects of terrorist acts, the war on terrorism, potential war with Iraq, potential conflict or crisis with North Korea and other global developments;

• 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;

• product demand 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 favorable collective bargaining agreements;

• new technological developments that could affect the operations and prospects of HEI’s subsidiaries or their competitors;

• federal, state and international governmental and regulatory actions, including changes in laws, rules and regulations applicable to HEI and its subsidiaries; 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); and changes in taxation;

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

• the effects of changes in accounting principles applicable to HEI and its subsidiaries;

• the effects of changes by securities rating agencies in the ratings of the securities of HEI and Hawaiian Electric Company, Inc. (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 ASB’s mortgage servicing rights;

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

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

• the risks of suffering losses that are uninsured; and

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

Forward-looking statements speak only as of the date of the report, presentation or filing in which they are made.

2

Selected Financial Data

Hawaiian Electric Industries, Inc. and Subsidiaries
Years ended December 31	2002			2001			2000			1999			1998
(dollars in thousands, except per share amounts)
Results of operations
Revenues	$	1,653,701		$	1,727,277		$	1,732,311		$	1,518,826		$	1,480,392
Net income (loss)
Continuing operations	$	118,217		$	107,746		$	109,336		$	96,426		$	97,262
Discontinued operations		—			(24,041	)		(63,592	)		421			(12,451	)
	$	118,217		$	83,705		$	45,744		$	96,847		$	84,811
Basic earnings (loss) per common share
Continuing operations	$	3.26		$	3.19		$	3.36		$	3.00		$	3.04
Discontinued operations		—			(0.71	)		(1.95	)		0.01			(0.39	)
	$	3.26		$	2.48		$	1.41		$	3.01		$	2.65
Diluted earnings per common share	$	3.24		$	2.47		$	1.40		$	3.00		$	2.64
Return on average common equity		12.0	%		9.5	%		5.4	%		11.6	%		10.3	%
Return on average common equity-continuing operations *		12.0	%		12.2	%		13.0	%		11.5	%		11.8	%
Financial position **
Total assets	$	8,876,503		$	8,517,943		$	8,518,694		$	8,288,647		$	8,194,367
Deposit liabilities		3,800,772			3,679,586			3,584,646			3,491,655			3,865,736
Securities sold under agreements to repurchase		667,247			683,180			596,504			661,215			523,800
Advances from Federal Home Loan Bank		1,176,252			1,032,752			1,249,252			1,189,081			805,581
Long-term debt		1,106,270			1,145,769			1,088,731			977,529			899,598
HEI- and HECO-obligated preferred securities of trust subsidiaries		200,000			200,000			200,000			200,000			200,000
Preferred stock of subsidiaries
Subject to mandatory redemption		—			—			—			—			33,080
Not subject to mandatory redemption		34,406			34,406			34,406			34,406			48,406
Stockholders’ equity		1,046,300			929,665			839,059			847,586			826,972
Common stock
Book value per common share **	$	28.43		$	26.11		$	25.43		$	26.31		$	25.75
Market price per common share
High		49.00			41.25			37.94			40.50			42.56
Low		34.55			33.56			27.69			28.06			36.38
December 31		43.98			40.28			37.19			28.88			40.25
Dividends per common share		2.48			2.48			2.48			2.48			2.48
Dividend payout ratio		76	%		100	%		176	%		82	%		94	%
Dividend payout ratio-continuing operations		76	%		78	%		74	%		83	%		82	%
Market price to book value per common share **		155	%		154	%		146	%		110	%		156	%
Price earnings ratio ***		13.5	x		12.6	x		11.1	x		9.6	x		13.2	x
Common shares outstanding (thousands) **		36,809			35,600			32,991			32,213			32,116
Weighted-average		36,278			33,754			32,545			32,188			32,014
Stockholders ****		34,901			37,387			38,372			39,970			40,793
Employees **		3,220			3,189			3,126			3,262			3,722

* Net income from continuing operations divided by average common equity.

** At December 31.

*** Calculated using December 31 market price per common share divided by basic earnings per common share from continuing operations.

**** At December 31. Registered stockholders plus participants in the HEI Dividend Reinvestment and Stock Purchase Plan who are not registered stockholders. At February 12, 2003, HEI had 34,284 registered stockholders and participants.

The Company discontinued its residential real estate operations in 1998 and its international power operations in 2001. See Note 13, “Discontinued operations,” in the “Notes to Consolidated Financial Statements.” In 1999, the Company sold Young Brothers, Limited and substantially all of the operating assets of Hawaiian Tug & Barge Corp. Also see “Commitments and contingencies” in Note 3 in the “Notes to Consolidated Financial Statements” for a discussion of certain contingencies that could adversely affect future results of operations.

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

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

Strategy

HEI’s strategy is to focus its resources on its two core operating businesses that provide electric public utility and banking services in the State of Hawaii. The success of this strategy will be heavily influenced by Hawaii’s general economic conditions and tourism.

In addition, key to achieving returns from the electric utility business is containing costs and ensuring customer satisfaction through reliable service and close customer relationships. With large power users in the electric utilities’ service territories, such as the U.S. military, hotels and state and local government, management believes that maintaining customer satisfaction is a critical component in achieving kilowatthour (KWH) sales and revenue growth in Hawaii over time. The electric utilities have established programs that offer these customers specialized services and energy efficiency audits to help them save on energy costs. Reliability projects remain a priority for HECO and its subsidiaries. For example, on Oahu, planning has begun for an overhaul and interface of key operating systems, including a new system operations center (subject to approval by the Public Utilities Commission) integrated with new customer information and outage management systems to ensure the most efficient deployment of generators and earlier and faster responses to outages. The electric utilities’ long-term plan to meet Hawaii’s future energy needs also 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.

American Savings Bank, F.S.B. and its subsidiaries (collectively, ASB) is expanding its traditional consumer focus to be a full-service community bank serving both individual and business customers. Key to ASB’s success will be its ability to increase its net interest income while minimizing loan losses. ASB is diversifying its loan portfolio from single-family home mortgages to higher-yielding consumer, business and commercial real estate loans. To manage this shift in assets, ASB has hired experienced business lending personnel and has established an appropriate risk management infrastructure.

HEI and its subsidiaries (collectively, the Company) from time to time consider 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.

Results of operations

The Company reported basic earnings per share from continuing operations of $3.26 in 2002 compared to $3.19 in 2001, reflecting the improved results of the electric utility, bank and “other” segments, partly offset by the impact of more shares outstanding. Basic earnings per share for 2002 increased 31% from 2001 primarily due to prior year net losses from discontinued operations.

The electric utilities’ net income for 2002 increased 2% from 2001 as KWH sales increased 1.9% and interest expense decreased 6%. ASB reported 16% higher net income for 2002 reflecting higher net interest and fee income, a lower provision for loan losses and no goodwill amortization in 2002, partly offset by higher other general and administrative expenses. The “other” segment reported $0.9 million lower net losses in 2002 compared to 2001 primarily due to lower interest expense. In 2001, the HEI Board of Directors adopted a plan to exit the international power business and a net loss from discontinued operations of $23.6 million was recorded for the year, including the write-off of a China project and the writedown of an investment in Cagayan Electric Power & Light Co., Inc. (CEPALCO). In 2000, the net loss of $63.6 million for discontinued operations was primarily due to the losses from and write-off of HEI Power Corp.’s (HEIPC’s) indirect investment in East Asia Power Resources Corporation, a Philippines holding company primarily engaged in the electric generation business in Manila and Cebu.

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Economic conditions

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

Hawaii’s economy continues to recover from the downturn immediately following the September 11, 2001 terrorist attacks and the weak economic performances in the U.S. mainland and Japan. Hawaii’s real gross state product grew by an estimated 2.1% in 2002, largely driven by a moderate recovery in tourism and continued strength in the local construction and real estate industries. Despite the lagging international market, total visitor arrivals grew 0.9% in 2002 due to strong recovery in the domestic market. Domestic visitor days grew 5% to a record high in 2002 and hotel occupancy increased 1.1% in 2002 over 2001.

The construction and real estate industries, stimulated by low interest rates, also grew in 2002 over strong results in 2001. Construction spending increased by 13.4% for the first 10 months of 2002 and the number of construction jobs increased 3.6% in 2002 over 2001. Private building permits, an indicator of future construction activity, increased by 11.7% in 2002 over 2001. Residential real estate sales also improved in 2002, with Oahu home sales up 14.7% and the median Oahu home resale price up 11.7% over 2001.

Hawaii’s economy is expected to continue to have moderate growth in 2003, barring a war with Iraq, a conflict or crisis with North Korea or other global developments that would heighten international security concerns or derail the modest economic recovery currently underway in the U.S. mainland and Japan. Under this scenario of recovery in tourism and continued strength in the construction and real estate industries, the State of Hawaii Department of Business, Economic Development and Tourism (DBEDT) expects real growth of 2.1% again in 2003. Economic growth is also signaled by the Hawaii index of leading economic indicators (maintained by DBEDT), which has risen nine straight months through October 2002 and indicates improving economic conditions over the next five to ten months. A potential war with Iraq, increasing tensions with North Korea and the threat of major new terroristic events in the U.S. are key uncertainties and risks to Hawaii’s economic growth. Should such global events occur, people may be reluctant to travel and Hawaii’s visitor industry would suffer. Any military troop deployments out of Hawaii will also have a negative economic impact.

Following is a general discussion of HEI’s consolidated results that should be read in conjunction with the segment discussions that follow.

Consolidated

(in millions, except per share amounts)	2002			% change		2001			% change		2000
Revenues	$	1,654		(4	)	$	1,727		—		$	1,732
Operating income		266		4			256		(1	)		258
Income from continuing operations	$	118		10		$	108		(1	)	$	109
Loss from discontinued operations		—		100			(24	)	62			(63	)
Net income	$	118		41		$	84		83		$	46
Basic earnings (loss) per share
Continuing operations	$	3.26		2		$	3.19		(5	)	$	3.36
Discontinued operations		—		100			(0.71	)	64			(1.95	)
	$	3.26		31		$	2.48		76		$	1.41
Weighted-average number of common shares outstanding		36.3		7			33.8		4			32.5
Dividend payout ratio		76	%				100	%				176	%
Dividend payout ratio – continuing operations		76	%				78	%				74	%

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• The increase in 2002 net income over 2001 net income was due to the lower losses from discontinued operations (nil in 2002), the electric utilities’ 2% higher net income, ASB’s 16% higher net income and the “other” segment’s 3% lower net losses.

• The increase in 2001 net income over 2000 net income was due to the lower losses from discontinued operations, the electric utilities’ 1% higher net income and ASB’s 19% higher net income, partly offset by the “other” segment’s 57% higher net losses.

• Shareholder dividends are declared and paid quarterly by HEI at the discretion of HEI’s Board of Directors. HEI’s Board maintained the 2002 annual dividend per common share at $2.48. The annual dividend per common share was $2.48 in each of 2001 and 2000.

• HEI and its predecessor company, HECO, have paid dividends continuously since 1901. On January 21, 2003, HEI’s Board maintained the quarterly dividend of $0.62 per common share. At the indicated annual dividend rate of $2.48 per share and the closing share price on February 12, 2003 of $38.90, HEI’s dividend yield was 6.4%.

Following is a general discussion of revenues, expenses and net income or loss by business segment. Additional segment information is shown in Note 2 in the “Notes to Consolidated Financial Statements.”

Electric utility

(in millions, except per barrel amounts and number of employees)	2002			% change		2001			% change		2000
Revenues 1	$	1,257		(2	)	$	1,289		1		$	1,277
Expenses
Fuel oil		311		(10	)		347		(4	)		363
Purchased power		326		(3	)		338		9			311
Other		425		4			410		—			410
Operating income		195		1			194		—			193
Allowance for funds used during construction		6		(11	)		6		(22	)		8
Net income		90		2			88		1			87
Return on average common equity		10.0	%				10.4	%				10.7	%
Average price per barrel of fuel oil 1	$	29.10		(13	)	$	33.49		—		$	33.44
Kilowatthour sales		9,544		2			9,370		1			9,272
Number of employees (at December 31)		1,894		(2	)		1,930		(1	)		1,941

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

• In 2002, the electric utilities’ revenues decreased by 2%, or $32 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 higher 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 independent power producer (IPP) who was able to produce only an average of about 5.6 megawatts (MW) of firm capacity since April 2002 compared to the 30 MW the IPP contracted to provide to Hawaii Electric Light Company, Inc. (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, partly offset by a 1% decrease in taxes, other than income taxes. The 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.

• In 2001, the electric utilities’ revenues increased by 1%, or $12 million, from 2000 primarily due to a 1.1% increase in KWH sales of electricity ($12 million) and a HELCO rate increase ($6 million), partly offset by lower

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energy costs ($9 million). The increase in KWH sales was primarily due to an increase in the number of customers and warmer temperatures, which typically result in higher air conditioning usage. Through August 2001, KWH sales were up 1.6%. However, declining tourism and the weakened economy after the September 11, 2001 terrorist attacks caused a 0.4% decrease in KWH sales in the fourth quarter compared to the same period last year. Operating income for 2001 was comparable to 2000. Fuel oil expense decreased 4% due primarily to fewer KWHs generated. Purchased power expense increased 9% due primarily to higher purchased capacity payments resulting from increased capacity (including a new IPP in August 2000), higher availability and more KWHs purchased, partly offset by lower energy prices. Other expenses were flat reflecting a 6% decrease in maintenance expense, offset by a 1% increase in other operation expense, a 2% increase in depreciation expense and a 1% increase in taxes, other than income taxes. AFUDC for 2001 was 22% lower than 2000 due to a lower base on which AFUDC is calculated. Interest expense decreased 4% from 2000 due to lower short-term borrowings and lower interest rates.

Recent rate requests

HEI’s electric utility subsidiaries initiate PUC proceedings from time to time to request electric rate increases to cover rising operating costs (e.g., the cost of purchased power) and the cost of plant and equipment, including the cost of new capital projects to maintain and improve service reliability. As of February 12, 2003, the return on average common equity (ROACE) found by the PUC to be reasonable in the most recent final rate decision for each utility was 11.40% for HECO (decision and order (D&O) issued on December 11, 1995, based on a 1995 test year), 11.50% for HELCO (D&O issued on February 8, 2001, based on a 2000 test year) and 10.94% for Maui Electric Company, Limited (MECO) (amended D&O issued on April 6, 1999, based on a 1999 test year). For 2002, the actual simple average ROACEs (calculated under the rate-making method and reported to the PUC) for HECO, HELCO and MECO were 11.33%, 7.52% and 10.30%, respectively.

Hawaiian Electric Company, Inc. HECO has not initiated a rate case for several years, but in 2001 it committed to initiate a rate case within three years, using a 2003 or 2004 test year, as part of the agreement described below under “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 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.

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 “Certain factors that may affect future results and financial condition–Electric utility–Other regulatory and permitting contingencies” and “HELCO power situation” in Note 3 of the “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 rest of the rate case. The rider provides the rates, terms and conditions for obtaining backup and supplemental electric power from the utility when a customer obtains all or part of its electric power from sources other than HELCO.

Other regulatory matters

Demand-side management programs—lost margins and shareholder incentives. HECO, HELCO and MECO’s energy efficiency demand-side management (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’ forecasted levels of participation, and are subject to two adjustments based on (1) the actual level of participation and (2) the results of impact

7

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, under which HECO’s three commercial and industrial DSM programs and two residential DSM programs would be continued until HECO’s next rate case, which, under the agreements, HECO committed to file using a 2003 or 2004 test year and following the PUC’s rules for determining the test year. The agreements for the temporary continuation of HECO’s existing DSM programs were in lieu of HECO continuing to seek approval of new 5-year DSM programs. Any DSM programs to be in place after HECO’s next rate case will be determined as part of the case. Under the agreements, HECO will cap the recovery of lost margins and shareholder incentives if such recovery would cause HECO to exceed its current authorized return on rate base. HECO also agreed it will not pursue the continuation of lost margins recovery and shareholder incentives through a surcharge mechanism in future rate cases. Consistent with the HECO agreements, in October 2001, HELCO and MECO reached agreements with the Consumer Advocate and filed requests to continue their four existing DSM programs. In November 2001, the PUC issued orders (one of which was later amended) that, subject to certain reporting requirements and other conditions, approved (1) the agreements regarding the temporary continuation of HECO’s five existing DSM programs until HECO’s next rate case and (2) the agreements regarding the temporary continuation of HELCO’s and MECO’s DSM programs until one year after the PUC makes a revenue requirements determination in HECO’s next rate case. Under the orders, however, HELCO and MECO are allowed to recover only lost margins and shareholder incentives accrued through the date that interim rates are established in HECO’s next rate case, but may request to extend the time of such accrual and recovery for up to one additional year. In 2002, MECO’s revenues from shareholder incentives were $0.7 million lower than the amount that would have been recorded if MECO had not agreed to cap such incentives when its authorized return on rate base was exceeded. Also in 2002, HELCO slightly exceeded its authorized return on rate base. If an adjustment is required due to the higher rate of return, HELCO may need to reduce its recorded shareholder incentives by approximately $30,000. In 2002, HECO did not exceed its authorized return on rate base.

Collective bargaining agreements

In August 2000, HECO, HELCO and MECO employees represented by the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260, ratified collective bargaining agreements covering approximately 62% of the employees of HECO, HELCO and MECO. The collective bargaining agreements (including benefit agreements) cover a three-year period from November 1, 2000 through October 31, 2003 and expire at midnight on October 31, 2003. The main provisions of the agreements include noncompounded wage increases of 2.25% effective November 1, 2000, 2.5% effective November 1, 2001 and 2.5% effective November 1, 2002. The agreements also included increased employee contributions to medical premiums. The electric utilities expect to begin negotiations for new collective bargaining agreements in the third quarter of 2003.

Legislation

Congress and the Hawaii legislature periodically consider legislation that could have positive or negative effects on the utilities and their customers. The 2003 Hawaii legislature is considering measures that would undertake a comprehensive audit of Hawaii’s electric utility regulatory policies, energy policies and support for reducing Hawaii’s dependence on imported petroleum for electrical generation. The legislature is also considering a measure to remove the cap for net energy metering. Management cannot predict whether these proposals will be enacted into law.

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,

8

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

The electric utilities currently support renewable sources in various ways, including their solar water heating and heat pump programs and their purchased power contracts with nonutility generators using renewable sources (e.g., refuse-fired, geothermal, hydroelectric and wind turbine generating systems). The electric utilities continue to initiate and support many renewable energy research and development projects to help develop these technologies (e.g., photovoltaic projects). They are also conducting integrated resource planning to evaluate the use of more renewables and, in December 2002, HECO formed a subsidiary, Renewable Hawaii, Inc., to invest in renewable energy projects. About 6.8% of electricity sales for 2002 were from renewable resources (as defined under the renewable portfolio standard law). Despite their efforts, the electric utilities believe it may be difficult to increase this percentage to the percentages targeted in the 2001 Hawaii legislation, particularly if sales of electricity increase in future years as projected. Thus, at this time, management cannot predict the impact of this law or of other proposed congressional and Hawaii legislation on the utilities or their customers.

Bank

(in millions)	2002			% change		2001			% change		2000
Revenues	$	399		(10	)	$	445		(1	)	$	451
Net interest income		193		4			186		1			185
Operating income		93		13			82		17			70
Net income		56		16			49		19			41
Return on average common equity		12.9	%				12.3	%				11.0	%
Interest-earning assets
Average balance 1	$	5,745		2		$	5,618		1		$	5,562
Weighted-average yield		6.03	%	(15	)		7.11	%	(7	)		7.61	%
Interest-bearing liabilities
Average balance 1	$	5,488		1		$	5,417		—		$	5,418
Weighted-average rate		2.79	%	(29	)		3.94	%	(11	)		4.41	%
Interest rate spread		3.24	%	2			3.17	%	(1	)		3.20	%

¹ Calculated using the average daily balances during 2002 and 2001 and average month-end balances during 2000.

Earnings of ASB depend primarily on net interest income, which is the difference between interest income earned on interest-earning assets (loans receivable and investment and mortgage-related securities) and interest expense incurred on interest-bearing liabilities (deposit liabilities and borrowings). ASB’s loan volumes and yields are affected by market interest rates, competition, demand for real estate financing, availability of funds and management’s responses to these factors. Advances from the Federal Home Loan Bank (FHLB) of Seattle and securities sold under agreements to repurchase continue to be significant sources of funds for ASB, but are a higher costing source of funds than core deposits. Other factors that may significantly affect ASB’s operating results include the gains or losses on sales of securities available for sale, the level of fee income, the provision for loan losses and expenses from operations.

The following table sets forth average balances, interest and dividend income, interest expense and weighted-average yields earned and rates paid for certain categories of interest-earning assets and interest-bearing liabilities for the years indicated. Average balances for each year have been calculated using the average month-end or daily average balances during the year.

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	Years ended December 31,
(in thousands)	2002			2001			2000
Loans
Average balances 1	$	2,844,341		$	2,963,521		$	3,215,879
Interest income 2		203,082			231,858			254,502
Weighted-average yield		7.14	%		7.82	%		7.91	%
Mortgage-related securities
Average balances	$	2,654,302		$	2,345,630		$	2,058,706
Interest income		135,252			152,181			152,340
Weighted-average yield		5.10	%		6.49	%		7.40	%
Investments 3
Average balances	$	246,321		$	308,712		$	287,906
Interest and dividend income		7,896			15,612			16,733
Weighted-average yield		3.21	%		5.06	%		5.81	%
Total interest-earning assets
Average balances	$	5,744,964		$	5,617,863		$	5,562,491
Interest and dividend income		346,230			399,651			423,575
Weighted-average yield		6.03	%		7.11	%		7.61	%
Deposits
Average balances	$	3,717,553		$	3,638,136		$	3,537,312
Interest expense		73,631			116,531			119,192
Weighted-average rate		1.98	%		3.20	%		3.37	%
Borrowings
Average balances	$	1,770,831		$	1,778,766		$	1,880,952
Interest expense		79,251			97,054			119,683
Weighted-average rate		4.48	%		5.46	%		6.36	%
Total interest-bearing liabilities
Average balances	$	5,488,384		$	5,416,902		$	5,418,264
Interest expense		152,882			213,585			238,875
Weighted-average rate		2.79	%		3.94	%		4.41	%
Net balance, net interest income and interest rate spread
Net balance	$	256,580		$	200,961		$	144,227
Net interest income		193,348			186,066			184,700
Interest rate spread		3.24	%		3.17	%		3.20	%

¹ Includes nonaccrual loans.

² Includes interest accrued prior to suspension of interest accrual on nonaccrual loans and loan fees of $4.2 million, $3.6 million and $3.4 million for 2002, 2001 and 2000, respectively.

³ Includes stock in the FHLB of Seattle.

• Net interest income before provision for losses for 2002 increased by $7.3 million, or 3.9%, over 2001. For 2002, net interest spread increased from 3.17% to 3.24% when compared to 2001 as ASB’s cost of interest-bearing liabilities decreased faster than the yield on its interest-earning assets. The decrease in the average loan portfolio balance for both 2002 and 2001 was due to the securitization of $0.4 billion in residential loans into Federal National Mortgage Association (FNMA) pass-through securities in June 2001. However, loan originations and purchases of mortgage-related securities caused the average balance of interest-earning assets to increase in 2002. Interest

10

rates fell to a 41-year low, spurring record loan production and refinancing. ASB also continued to aggressively build its business and commercial real estate lines of business in 2002, hiring experienced business bankers and commercial real estate loan officers. ASB’s business banking portfolio grew from $135 million in 2000 to $247 million in 2002. Its commercial real estate loan portfolio rose from $156 million in 2000 to $197 million in 2002. Even with the growth in these lending areas, mortgage lending will remain ASB’s primary lending program for some time to come. The increase in average deposit balances was primarily in core deposit balances. The provision for loan losses of $9.8 million in 2002 decreased by $2.8 million compared to 2001 as delinquencies have been at six-year lows. The strong Hawaii real estate market and low interest rates gave debtors the opportunity to sell their properties or refinance before defaulting on loans. In addition, ASB improved its collections efforts. These factors contributed to the lower delinquency levels during 2002. Residential and commercial real estate loan delinquencies have decreased during the year and lower loan loss reserves were required for those lines of business. The growth of the business loan portfolio has required additional loan loss reserves on those loans. The allowance for loan losses on consumer loans has remained essentially the same during the year. See “Quantitative and Qualitative Disclosures about Market Risk – Bank.”

In the near term, ASB is experiencing some compression in its interest rate spread as the very low short-term interest rates are spurring prepayments and reducing its yield on assets while the cost of funds has essentially reached a floor and cannot be reduced much further. ASB is in the unusual position where a moderate increase in interest rates would likely be beneficial to its earnings.

Other income for 2002 increased by $8.1 million, or 18.0%, over 2001. Fee income from other financial services increased by $4.1 million for 2002 compared to 2001 due to higher fee income from its debit and automated teller machines (ATM) cards resulting from ASB’s expansion of its debit card base and its introduction of new ATM services in 2001. ASB had $6.3 million of higher fee income from its deposit liabilities for 2002 compared to 2001 primarily from service charges as a result of restructuring of deposit products. Fee income on other financial products increased $1.6 million from 2001 to 2002 as a result of increased fee income from Bishop Insurance Agency of Hawaii, Inc. (BIA) which was acquired in March 2001. Fee income on loans serviced for others for 2002 decreased by $2.6 million compared to 2001 as the bank recorded writedowns of its mortgage servicing rights of $2.2 million primarily due to faster prepayments on its servicing portfolio. ASB sold securities for a net loss of $0.6 million in 2002 compared to a net gain of $8.0 million in 2001. In 2001, ASB recognized a loss of $6.2 million on the writedown of investments in trust certificates to their then-current estimated fair value. ASB disposed of the trust certificates in 2001.

General and administrative expenses for 2002 increased by $7.3 million, or 5.4%, over 2001. Compensation and benefits for 2002 was $7.7 million higher than in 2001 primarily due to increased investment in ASB’s workforce to support its strategic initiatives. Consulting expenses for 2002 increased by $3.9 million over 2001 for consulting services to implement strategic changes to become a full-service community bank. The amortization of intangibles decreased by $5.0 million for 2002 compared to 2001 primarily because goodwill was not amortized as a result of the adoption of Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets” on January 1, 2002.

• Net interest income before provision for losses for 2001 increased by $1.4 million, or 0.7%, over the same period in 2000. For 2001, net interest spread decreased from 3.20% to 3.17% when compared to 2000 as ASB’s yield on its interest-earning assets decreased faster than the cost of interest-bearing liabilities. The decrease in the average loan portfolio balance and the increase in mortgage-related securities was due in part to the securitization of $0.4 billion in residential loans into FNMA pass-through securities in June 2001. Also, average loans decreased because of high repayments in ASB’s residential loan portfolio. The increase in average deposit balances was primarily in core deposit balances.

Other income for 2001 increased by $17.6 million, or 64.6%, over 2000. Fee income from other financial services increased by $2.8 million for 2001 compared to 2000 due to higher fee income from its debit and ATM cards resulting from ASB’s expansion of its debit card base and its introduction of new check cashing ATMs in

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August 2001. ASB had $0.6 million of higher fee income from its deposit liabilities for 2001 compared to 2000 primarily from service charges as a result of restructuring of deposit products. Fee income on other financial products increased $5.2 million from 2000 to 2001 due to fee income earned by BIA which was acquired in March 2001 and higher fee income from sales of annuities. Gains on sales of investments and mortgage-related securities was $8.0 million in 2001 and nil in 2000. However, for 2001, ASB recognized a $0.3 million higher loss on the writedown of investments in trust certificates to their then-current estimated fair value compared to 2000.

General and administrative expenses for 2001 increased by $7.5 million, or 5.8%, over 2000. Compensation and benefits for 2001 was $3.5 million, or 7%, higher than 2000 and data processing expenses increased by $3.5 million, or 51%, due to higher service bureau expense. In September 2000, ASB converted its in-house data processing system to a third party service bureau.

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

• During 2002, ASB increased its allowance for loan losses by $3.2 million. As of December 31, 2002 and 2001, ASB’s allowance for loan losses was 1.60% and 1.42%, respectively, of average loans outstanding.

ASB’s nonaccrual and renegotiated loans represented 0.9% and 1.5% of total loans outstanding at December 31, 2002 and 2001, respectively. ASB’s delinquencies have been at six-year lows. See Note 4 in the “Notes to Consolidated Financial Statements.”

• In March 1998, ASB formed a subsidiary, ASB Realty Corporation, which elects to be taxed as a real estate investment trust (REIT). For a discussion of a state tax assessment relating to the tax treatment of dividends paid to ASB by ASB Realty Corporation, see Note 9 in the “Notes to Consolidated Financial Statements.”

Regulation

ASB is subject to extensive regulation, principally by the Office of Thrift Supervision (OTS) and the Federal Deposit Insurance Corporation (FDIC). Depending on its level of regulatory capital and other considerations, these regulations could restrict the ability of ASB to compete with other institutions and to pay dividends to its shareholders. See the discussions below under “Liquidity and capital resources—Bank” and “Certain factors that may affect future results and financial condition—Bank.”

Other

(in millions)	2002			% change		2001			% change		2000
Revenues 1	$	(3	)	59		$	(7	)	NM		$	4
Operating loss		(21	)	(8	)		(20	)	(255	)		(6	)
Net loss		(28	)	3			(29	)	(57	)		(19	)

¹ Including writedowns of and net losses from investments.

NM Not meaningful.

The “other” business segment includes results of operations of HEI Investments, Inc. (HEIII), a company primarily holding investments in leveraged leases (excluding foreign investments reported in discontinued operations); Pacific Energy Conservation Services, Inc., a contract services company primarily providing windfarm

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operational and maintenance services to an affiliated electric utility; ProVision Technologies, Inc., a company formed to sell, install, operate and maintain on-site power generation equipment and auxiliary appliances in Hawaii and the Pacific Rim; HEI Properties, Inc. (HEIPI), a company holding passive investments; Hawaiian Electric Industries Capital Trust I, HEI Preferred Funding, LP and Hycap Management, Inc., financing entities formed to effect the issuance of 8.36% Trust Originated Preferred Securities; The Old Oahu Tug Service, Inc. (TOOTS), a maritime freight transportation company that ceased operations in 1999; other inactive subsidiaries; HEI and HEI Diversified, Inc. (HEIDI), holding companies; and eliminations of intercompany transactions.

• HEIII, a company primarily holding investments in leveraged leases (excluding foreign investments reported in discontinued operations), recorded net income of $1.5 million in 2002, $1.5 million in 2001 and $0.9 million in 2000.

• HEIPI, a company holding passive investments, recorded net losses of $0.6 million in 2002 and $1.0 million in 2001 and net income of $1.4 million in 2000. HEIPI recorded its share of the net losses or income of Utech Venture Capital Corporation ($0.3 million net loss in 2002 and $1.2 million net loss in 2001 compared to $1.5 million net income in 2000). As of December 31, 2002, the Company’s venture capital investments amounted to $3.5 million.

• Corporate and the other subsidiaries’ revenues in 2002 and 2001 include $4.5 million and $8.7 million, respectively, of pretax writedowns ($2.9 million and $5.6 million, respectively, net of taxes) of the income notes that HEI purchased in May and July 2001 in connection with the termination of ASB’s investments in trust certificates. As of December 31, 2002, the fair value and carrying value of the income notes was $8.0 million. See Note 4 of the “Notes to Consolidated Financial Statements.” HEI could incur additional losses from the ultimate disposition of these investments or from further “other-than-temporary” declines in their fair value.

HEI Corporate operating, general and administrative expenses (including labor, employee benefits, incentive compensation, charitable contributions, legal fees, consulting, rent, supplies and insurance) were $15.6 million in 2002, $10.5 million in 2001 and $7.3 million in 2000. The 2002 increase in corporate operating, general and administrative expenses compared to 2001 was primarily the result of legal and other expenses incurred in connection with the income note litigation beginning in 2001 amounting to $4.3 million in 2002 and $0.7 million in 2001. The 2001 increase in corporate operating, general and administrative expenses compared to 2000 was partially a result of higher executive compensation and stock option expense. Corporate and the other subsidiaries’ net loss was $29.2 million in 2002, $29.6 million in 2001 and $20.9 million in 2000, the majority of which is interest expense.

• The “other” segment’s interest expense was $28.1 million in 2002, $31.7 million in 2001 and $28.2 million in 2000. In 2002, interest expense for the “other” segment decreased 11% due to lower rates and lower average borrowings. In 2002, medium-term notes were repaid as they matured primarily with the proceeds from the sale of 1.5 million shares of common stock in a registered public offering in November 2001. In 2001, interest expense for the “other” segment increased 12% due to higher average borrowings.

Effects of inflation

U.S. inflation, as measured by the U.S. Consumer Price Index, averaged an estimated 1.6% in 2002, 2.8% in 2001 and 3.4% in 2000. Hawaii inflation, as measured by the Honolulu Consumer Price Index, averaged an estimated 1.2% in 2002, 1.2% in 2001 and 1.7% in 2000. Although the rate of inflation over the past several years has been relatively low, inflation continues to have an impact on HEI’s operations.

Inflation increases operating costs and the replacement cost of assets. Subsidiaries with significant physical assets, such as the electric utilities, 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” in Note 1 of the “Notes to Consolidated Financial Statements.”

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Liquidity and capital resources

Consolidated

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 construction programs and investments and to cover debt and other cash requirements in the foreseeable future.

The Company’s total assets were $8.9 billion at December 31, 2002 and $8.5 billion at December 31, 2001.

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

December 31	2002				2001
(in millions)
Long-term debt	$	1,106	46	%	$	1,146	50	%
HEI- and HECO-obligated preferred securities of trust subsidiaries		200	9			200	9
Preferred stock of subsidiaries		34	1			34	1
Common stock equity		1,046	44			930	40
	$	2,386	100	%	$	2,310	100	%

As of February 12, 2003, the Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HEI and HECO securities were as follows:

	S&P	Moody’s
HEI
Commercial paper	A-2	P-2
Medium-term notes	BBB	Baa2
HEI-obligated preferred securities of trust subsidiary	BB+	Ba1
HECO
Commercial paper	A-2	P-2
Revenue bonds (insured)	AAA	Aaa
Revenue bonds (noninsured)	BBB+	Baa1
HECO-obligated preferred securities of trust subsidiaries	BBB-	Baa2
Cumulative preferred stock (selected series)	NR	Baa3

NR Not rated.

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

In May 2002, S&P revised its credit outlook on HEI and HECO securities to stable from negative, citing “recovery in Hawaii’s economy, moderate construction spending, aggressive cost containment, limited competitive pressures, steady banking operations, and expectations for continued financial improvement.” In June 2001, Moody’s had revised its credit outlook on HEI and HECO securities to stable from negative, citing “significant improvements in the Hawaiian economy, the resulting strong financial performance of the company’s main operating subsidiaries, and a reduced emphasis on overseas investments.” In May 2002, Moody’s affirmed HEI’s medium-term note rating (Baa2) and S&P affirmed all of HEI’s and HECO’s ratings.

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

At December 31, 2002, $300 million of a registered medium-term note program was available for offering by HEI.

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From time to time, HEI and HECO each utilizes short-term debt, principally commercial paper, to support normal operations and for other temporary requirements. HECO also borrows short-term from HEI from time to time. HEI and HECO had average outstanding balances of commercial paper for 2002 of $0.8 million and $9.6 million, respectively. HEI and HECO had no commercial paper outstanding at December 31, 2002. Management believes that if HEI’s and HECO’s commercial paper ratings were to be downgraded, they might not be able to sell commercial paper under current market conditions.

At December 31, 2002, HEI and HECO maintained bank lines of credit totaling $70 million and $100 million, respectively (all maturing in 2003). On January 1, 2003, HECO reduced its total lines of credit to $90 million. These lines of credit are principally maintained by HEI and HECO to support the issuance of commercial paper and 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 was to reduce or eliminate access to the commercial paper markets. Lines of credit to HEI totaling $40 million contain provisions for revised pricing in the event of a ratings change (e.g., a ratings downgrade of HEI medium-term notes from BBB/Baa2 to BBB-/Baa3 by S&P and Moody’s, respectively, would result in a 15 to 50 basis points higher interest rate; a ratings upgrade from BBB/Baa2 to BBB+/Baa1 by S&P and Moody’s, respectively, would result in a 20 to 30 basis points lower interest rate). There are no such provisions in the other lines of credit available to HEI and HECO. Further, none of HEI’s or HECO’s line of credit agreements contain “material adverse change” clauses that would affect access to the lines of credit in the event of a ratings downgrade or other material adverse events. At December 31, 2002, the lines were unused. To the extent deemed necessary, HEI and HECO anticipate arranging similar lines of credit as existing lines of credit mature. See S&P and Moody’s ratings above and Note 5 in the “Notes to Consolidated Financial Statements.”

Operating activities provided net cash of $244 million in 2002, $259 million in 2001 and $265 million in 2000. Investing activities used net cash of $601 million in 2002, provided net cash of $28 million in 2001 and used net cash of $249 million in 2000. In 2002, net cash was used in investing activities largely due to banking activities (including the purchase of mortgage-related securities and origination and purchase of loans, net of repayments and sales of such securities) and HECO’s consolidated capital expenditures. Financing activities provided net cash of $151 million in 2002, used net cash of $97 million in 2001 and provided net cash of $77 million in 2000. In 2002, net cash provided by financing activities was affected by several factors, including net increases in deposits and advances from the FHLB and proceeds from the issuance of common stock, partly offset by the payment of common stock dividends and trust preferred securities distributions, net repayments of long-term debt and a net decrease in securities sold under agreements to repurchase.

In November 2001, HEI sold 1.5 million shares of its common stock in a registered public offering. Proceeds of approximately $54 million from the sale were used to make short-term investments or to make short-term loans to HECO, pending the ultimate application of the proceeds to repay long-term debt at maturity and for other general corporate purposes.

A portion of the net assets of HECO and ASB is not available for transfer to HEI in the form of dividends, loans or advances without regulatory approval. However, such restrictions are not expected to significantly affect the operations of HEI, its ability to pay dividends on its common stock or its ability to meet its cash obligations. See Note 11 in the “Notes to Consolidated Financial Statements.”

Total HEI consolidated financing requirements for 2003 through 2007, including net capital expenditures (which exclude the allowance for funds used during construction and capital expenditures funded by third-party contributions in aid of construction), long-term debt retirements and net financial activities of ASB, are estimated to total $1.3 billion. Of this amount, approximately $0.7 billion is for net capital expenditures (mostly relating to the electric utilities’ net capital expenditures described below) and $0.3 billion is for the retirement or maturity of long-term debt. HEI’s consolidated internal sources (primarily consolidated cash flows from operations comprised mainly of net income, adjusted for noncash income and expense items such as depreciation, amortization and deferred taxes, and changes in working capital), after the payment of dividends, are expected to provide approximately 71% of the consolidated financing requirements (approximately 93% excluding long-term debt retirements), with debt and equity financing providing the remaining requirements. Additional debt and/or equity financing may be required to fund unanticipated expenditures not included in the 2003 through 2007 forecast, such as increases in the costs of or an acceleration of the construction of capital projects of the electric utilities, unbudgeted acquisitions or investments in new businesses, significant increases in retirement benefit funding requirements that might be

15

required if there were significant declines in the market value of pension plan assets or changes in actuarial assumptions and higher tax payments that would result if tax positions taken by the Company do not prevail.

As further explained in Note 8 in the “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 is 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 may choose to make contributions to the pension plans in 2003. The electric utilities’ 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. Due to the sharp declines in U.S. equity markets beginning in 2000, the value of a significant portion of the assets held in the plans’ trusts to satisfy the obligations of the pension and other postretirement plans has decreased significantly. As a result, 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.

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

Electric utility

HECO’s consolidated capital structure was as follows:

December 31	2002				2001
(in millions)
Short-term borrowings	$	6	—	%	$	49	3	%
Long-term debt		705	40			685	39
HECO-obligated preferred securities of trust subsidiaries		100	6			100	6
Preferred stock		34	2			34	2
Common stock equity		923	52			877	50
	$	1,768	100	%	$	1,745	100	%

In 2002, the electric utilities’ investing activities used $103 million in cash, primarily for capital expenditures. Financing activities used net cash of $68 million, including $53 million for the payment of common and preferred stock dividends and preferred securities distributions and $43 million for the net repayment of short-term borrowings, partly offset by a $30 million net increase in long-term debt. Operating activities provided cash of $172 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 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 the revenue bonds are insured by a financial guaranty insurance policy issued by Ambac Assurance Corporation.

As of December 31, 2002, $16 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. Also as of December 31, 2002, an additional $25 million of special purpose revenue bonds were authorized by the Hawaii Legislature for issuance for the benefit of HELCO prior to the end of 2003.

The electric utilities’ consolidated financing requirements for 2003 through 2007, including net capital expenditures and long-term debt repayments, are estimated to total $0.7 billion. HECO’s consolidated internal sources (primarily consolidated cash flows from operations comprised mainly of net income, adjusted for noncash income and expense items such as depreciation, amortization and deferred taxes, and changes in working capital), after the payment of common stock and preferred stock dividends, are expected to provide cash in excess of the consolidated financing requirements and may be used to reduce the level of borrowings. HECO does not anticipate the need to issue common equity over the five-year period 2003 through 2007. Debt and/or equity financing may be required, however, to fund unanticipated expenditures not included in the 2003 through 2007 forecast, such as

16

increases in the costs of or an acceleration of the construction of capital projects, unbudgeted acquisitions or investments in new businesses and significant increases in retirement benefit funding requirements that might be required if there were significant declines in the market value of pension plan assets or changes in actuarial assumptions. The PUC must approve issuances, if any, of equity and long-term debt securities by HECO, HELCO and MECO.

Capital expenditures include the costs of projects that are required to meet expected load growth, to improve reliability and to replace and upgrade existing equipment. Net capital expenditures for the five-year period 2003 through 2007 are currently estimated to total $0.7 billion. Approximately 53% of forecasted 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 47% primarily for generation projects.

For 2003, electric utility net capital expenditures are estimated to be $158 million. Gross capital expenditures are estimated to be $183 million, including approximately $103 million for transmission and distribution projects, approximately $58 million for generation projects and approximately $22 million for general plant and other projects. Drawdowns of the remaining $16 million of proceeds from the Series 2002A sale of tax-exempt special purpose revenue bonds and the generation of funds from internal sources are expected to provide the cash needed for the net capital expenditures in 2003.

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

See Note 3 in the “Notes to Consolidated Financial Statements” for a discussion of fuel and power purchase commitments.

Bank

December 31	2002		% change		2001		% change
(in millions)
Assets	$	6,329	5		$	6,011	1
Available-for-sale mortgage-related securities		2,737	16			2,355	1,330
Held-to-maturity investment securities		90	6			84	(96	)
Loans receivable, net		2,994	5			2,858	(11	)
Deposit liabilities		3,801	3			3,680	3
Securities sold under agreements to repurchase		667	(2	)		683	15
Advances from FHLB		1,176	14			1,033	(17	)

As of December 31, 2002, ASB was the third largest financial institution in Hawaii based on assets of $6.3 billion and deposits of $3.8 billion.

ASB’s principal sources of liquidity are customer deposits, wholesale borrowings, the sale of mortgage loans into secondary market channels and the maturity and repayment of portfolio loans and mortgage-related securities. ASB’s deposits increased by $121 million during 2002. ASB’s principal sources of borrowings are advances from the FHLB and securities sold under agreements to repurchase from broker/dealers. At December 31, 2002, FHLB borrowings totaled $1.2 billion, representing 19% of assets. 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, 2002, ASB’s unused FHLB borrowing capacity was approximately $1.0 billion. At December 31, 2002, securities sold under agreements to repurchase totaled $0.7 billion, representing 11% of assets. 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, 2002, ASB had commitments to borrowers for undisbursed loan funds and unused lines and letters of credit of $0.8 billion.

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Management believes ASB’s current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.

In June 2001, ASB converted $0.4 billion in residential mortgage loans into FNMA pass-through securities. These securities were transferred into the investment securities portfolio and can serve as collateral for FHLB advances and other borrowings. The conversion of the loans also improves ASB’s risk-based capital ratio since less capital is needed to support federal agency securities than whole loans. In late June 2001, ASB sold $0.2 billion of the FNMA securities to improve ASB’s interest-rate risk profile. The securities sold were lower yielding 30-year fixed-rate securities with long remaining durations. ASB reinvested the proceeds into shorter duration fixed-rate and adjustable-rate securities.

At December 31, 2002, ASB had $15.8 million of loans on nonaccrual status, or 0.5% of net loans outstanding, compared to $37.6 million, or 1.3%, at December 31, 2001. At December 31, 2002 and 2001, ASB’s real estate acquired in settlement of loans was $12.1 million and $14.5 million, respectively.

In 2002, net cash of $497 million was used in investing activities largely for the purchase of mortgage-related securities and origination and purchase of loans, net of repayments and sales of such securities. Financing activities provided net cash of $213 million due to net increases in deposits and advances from the FHLB, partly offset by the payment of common and preferred stock dividends and a net decrease in securities sold under agreements to repurchase. Operating activities provided cash of $73 million.

ASB believes that a satisfactory regulatory capital position provides a basis for public confidence, affords protection to depositors, helps to ensure continued access to capital markets on favorable terms and provides a foundation for growth. FDIC regulations restrict the ability of financial institutions that are not well-capitalized to compete on the same terms as well-capitalized institutions, such as by offering interest rates on deposits that are significantly higher than the rates offered by competing institutions. As of December 31, 2002, ASB was well-capitalized (ratio requirements noted in parentheses) with a leverage ratio of 6.7% (5.0%), a Tier-1 risk-based capital ratio of 13.5% (6.0%) and a total risk-based capital ratio of 14.7% (10.0%).

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Selected contractual obligations and commitments

The following tables present aggregated information about certain contractual obligations and commercial commitments:

December 31, 2002	Payment due by period
(in millions)	Less than 1 year		1-3 years		4-5 years		After 5 years		Total
Contractual obligations
Deposit liabilities
Commercial checking	$	242	$	—	$	—	$	—	$	242
Other checking		621		—		—		—		621
Passbook		1,226		—		—		—		1,226
Money market		443		—		—		—		443
Term certificates		506		593		119		51		1,269
Total deposit liabilities	$	3,038	$	593	$	119	$	51	$	3,801
Securities sold under agreements to repurchase		305		362		—		—		667
Advances from Federal Home Loan Bank		273		711		192		—		1,176
Long-term debt		136		38		120		812		1,106
HEI and HECO-obligated preferred securities of trust subsidiaries		—		—		—		200		200
Operating leases, service bureau contract and maintenance agreements		19		26		9		20		74
Fuel oil purchase obligations (estimate based on January 1, 2003 fuel oil prices)		329		330		—		—		659
Purchase power obligations–minimum fixed capacity charges		123		241		236		1,607		2,207
	$	4,223	$	2,301	$	676	$	2,690	$	9,890

December 31, 2002
(in millions)
Other commercial commitments
Loan commitments and loans in process (primarily expiring in 2003)	$	91
Unused lines and letters of credit		701
	$	792

The tables above do not include other categories of obligations and commitments, such as trade payables, obligations under purchase orders, amounts that may become payable in future periods under collective bargaining and other employment agreements and employee benefit plans, and obligations that may arise under indemnities provided to purchasers of discontinued operations.

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Certain factors that may affect future results and financial condition

The Company’s results of operations and financial condition can be affected by numerous factors, many of which are beyond its control and could cause future results of operations to differ materially from historical results. The following is a discussion of certain of these factors.

Consolidated

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

Competition. The electric utility and banking industries are competitive and the Company’s success in meeting competition will continue to have a direct impact on the Company’s financial performance.

Electric utility. The electric utility industry in Hawaii has become increasingly competitive. IPPs are well established in Hawaii and continue to actively pursue new projects. Competition in the generation sector in Hawaii is moderated, however, by the scarcity of generation sites, various permitting processes and lack of interconnections to other electric utilities. Customer self-generation, with or without cogeneration, is a continuing competitive factor. Historically, HECO and its subsidiaries have been able to compete by offering customers economic alternatives that, among other things, employ energy efficient electrotechnologies such as the heat pump water heater. However, the number of customer self-generation projects that are being proposed or installed in Hawaii, particularly those involving combined heat and power (CHP) systems, is growing. CHP systems are a form of distributed generation (DG), and produce electricity and thermal energy from gas, propane or diesel-fired engines. In Hawaii, the thermal energy generally is used to heat water and, through an absorption chiller, drive an air conditioning system. The electric energy generated by these systems is usually lower in output than the customer’s load, which results in continued connection to the utility grid to make up the difference in electricity demand and to provide back up electricity.

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

In 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

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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 states 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.” HECO is unable to predict the ultimate outcome of the proceeding, which of the proposals (if any) advanced in the proceeding will be implemented or whether the parties will seek and obtain state legislative action on their proposals (other than the legislation described above under “Results of operations–Electric utility–Legislation”).

Bank. 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 brokers, finance companies and brokerage firms. These competitors offer a variety of lending and savings 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. 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 and other services offered. ASB believes that it is able to compete for such loans primarily through the competitive interest rates and loan fees it charges, the type of mortgage loan programs it offers and the efficiency and quality of the services it provides to individual borrowers and the business community.

ASB is expanding its traditional consumer focus to be a full-service community bank and is diversifying its loan portfolio from single-family home mortgages to higher-yielding business and commercial real estate loans. The origination of consumer, business banking 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 consumer, business banking and commercial real estate loans.

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

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 retirement benefits expense, net of amounts capitalized and income taxes, will be $12 million in 2003 as compared to net retirement benefits income of $4 million in 2002 (or $16 million less net income), partly as a result of the effect of the stock market decline on the performance of the assets in HEI’s master pension trust.

• Volatility in U.S. capital markets or higher delinquencies in the assets underlying the mortgage-related securities held by ASB and the income notes acquired by HEI in connection with ASB’s disposition of certain trust certificates may negatively impact their fair values in future periods. As of December 31, 2002, the fair value and carrying value of the mortgage-related securities held by ASB and the income notes held by HEI were $2.7 billion and $8.0 million, respectively.

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Interest rate risk is a significant risk of ASB’s operations. ASB actively manages this risk, including managing the relationship of its interest-sensitive assets to its interest-sensitive liabilities. See “Quantitative and Qualitative Disclosures about Market Risk.” HEI and HECO and its subsidiaries are exposed to interest rate risk primarily due to their borrowings. They attempt to manage this risk in part by incurring or refinancing debt in periods of low interest rates and by usually issuing fixed-rate rather than floating-rate long-term debt. As of December 31, 2002, the Company had no commercial paper outstanding and $100 million of floating-rate medium-term notes outstanding.

Federal government monetary policies and low interest rates have resulted in increased mortgage refinancing volume as well as accelerated prepayments of loans and securities. ASB’s interest rate spread, the difference between the yield on interest-earning assets and the cost of funds, was compressed in the fourth quarter of 2002 and may continue to be compressed if yields on assets decline more rapidly than the cost of funds.

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

Discontinued operations and asset dispositions. The Company has discontinued or sold its international power, maritime freight transportation and real estate operations in recent years. See Note 13 in the “Notes to Consolidated Financial Statements.” Problems may be encountered or liabilities may arise in the exit from these operations. For example, in accounting for the discontinuance of operations under accounting standards at the time of discontinuation, estimates were made by management concerning the amounts that would be realized upon the sale of those operations (including income tax benefits to be realized) and concerning the costs and liabilities that would be incurred in connection with the discontinuation. Management made these estimates based on the information available, but the amounts finally realized on disposition of the discontinued operations, and the amount of the liabilities and costs ultimately incurred in connection with those operations, may differ materially from the recorded amounts due to many factors, including changes in current economic and political conditions, both domestically and internationally. Management continues to monitor significant changes in economic and political conditions and the impact these developments may have on the Company’s net assets of discontinued operations. At December 31, 2002, the net assets of the discontinued international power and real estate operations amounted to $17 million.

In addition, in connection with prior dispositions of operations, additional unrecorded liabilities may arise if claims are asserted under indemnities provided in connection with the dispositions. For example, TOOTS is participating in the Honolulu Harbor environmental investigation on behalf of its former maritime freight transportation operations under an indemnity arrangement entered into in connection with the sale of those operations. See Note 3 in the “Notes to Consolidated Financial Statements.”

It is also possible that the Company may recover amounts relating to claims arising in connection with discontinued operations or the disposition of assets that have been written down. For example, HEIPC and its subsidiaries are pursuing recovery of the $25 million of costs incurred in connection with a joint venture interest in a China project that was previously expensed or written off when the Company decided to exit the international power business. Also, ASB is pursuing claims against a broker to recover losses incurred in connection with certain trust certificates acquired from the broker and subsequently disposed of by ASB. See Note 4 in the “Notes to Consolidated Financial Statements.” Pursuit of such recoveries may be costly and there can be no assurance that the pursuit of any of these claims will be successful or that any amounts will be recovered.

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 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 cost prohibitive. Similarly, the electric utilities have 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

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

An ongoing environmental investigation is the Honolulu Harbor environmental investigation described in Note 3 in the “Notes to Consolidated Financial Statements.” 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 electric utilities, including with respect to the Honolulu Harbor environmental investigation.

Prior to extending a loan secured by real property, ASB conducts due diligence to assess whether or not the property may present environmental risks and potential cleanup liability. In the event of default and foreclosure of a loan, ASB may become the owner of the mortgaged property. For that reason, ASB seeks to avoid lending upon the security of, or acquiring through foreclosure, any property with significant potential environmental risks; however, there can be no assurance that ASB will successfully avoid all such environmental risks.

Electric utility

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

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case. At December 31, 2002, HECO and its subsidiaries had recognized $16 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 using a 2003 or 2004 test year.

The rate schedules of the electric utility subsidiaries include energy cost adjustment clauses under which electric rates charged to customers are automatically adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power. In 1997 PUC decisions approving the electric utilities’ fuel supply contracts, the PUC noted that, in light of the length of the fuel supply contracts and the relative stability of fuel prices, the need for continued use of energy cost adjustment clauses would be the subject of investigation in a generic docket or in a future rate case. The electric utility subsidiaries believe that the energy cost adjustment clauses continue to be necessary. These clauses were continued in the most recent HELCO and MECO rate cases (final D&O’s issued in February 2001 and April 1999, respectively).

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

Fuel oil and purchased power. The electric utilities rely on fuel oil suppliers and independent power producers to deliver fuel oil and power, respectively. The Company estimates that 77% of the net energy generated and purchased by HECO and its subsidiaries in 2003 will be generated from the burning of oil. Purchased KWHs provided approximately 38.0% of the total net energy generated and purchased in 2002 compared to 39.0% in 2001 and 36.4% in 2000.

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 electric utilities’ major sources of oil, through their suppliers, are in Alaska, Australia and the Far East. Some, but not all, of the electric utilities’ 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. The following two major capital improvement utility projects, the Keahole project and the Kamoku-Pukele transmission line, have encountered opposition and the Keahole project has been seriously delayed.

Keahole project. In 1991, HELCO began planning to meet increased electric generation demand forecasted for 1994. HELCO’s plans were to install at its Keahole power plant two 20 MW combustion turbines (CT-4 and CT-5), followed by an 18 MW heat steam recovery generator, at which time these units would be converted to a 56 MW (net) dual-train combined-cycle unit. The timing of the installation of HELCO’s phased units has been revised on several occasions due to delays in obtaining an air permit and a land use permit amendment, in addition to delays caused by the commencement of lawsuits and administrative proceedings, many of which are on appeal or

24

otherwise have not been finally resolved. See Note 3 in the “Notes to Consolidated Financial Statements” for a more detailed description of the history and status of this project.

In September 2000, the Third Circuit Court of the State of Hawaii (Circuit Court) ruled that, absent a legal or equitable extension properly authorized by the Board of Land and Natural Resources (BLNR), HELCO’s further construction of CT-4 and CT-5 could not proceed because HELCO had not completed construction within the three-year construction period the Circuit Court found to be applicable to the project, unless the BLNR extended the construction period. HELCO subsequently obtained a BLNR order extending the construction period, but the Circuit Court then ruled, on September 19, 2002, that the BLNR did not have authority to grant the extension. As a result of this ruling, the construction of CT-4 and CT-5 has been suspended.

HELCO has appealed to the Hawaii Supreme Court both the Circuit Court 2000 ruling that there was a three-year construction period that had expired and the Circuit Court’s later ruling that BLNR could not extend the construction period. HELCO also filed motions to expedite the appeal and to stay the Circuit Court’s ruling pending the appeal. The Hawaii Supreme Court has denied the motion to expedite the appeal and the motion to stay the Circuit Court’s ruling pending appeal. In early 2003, the Hawaii Supreme Court also ruled that the appeal from the Circuit Court’s ruling in 2000 that the construction period had expired was not timely (even though the Circuit Court ruled at the time that its Order could not yet be appealed) and dismissed the appeal. HELCO cannot predict when its appeal of the Circuit Court’s ruling that the BLNR lacked authority to extend the construction deadline will be decided.

HELCO continues to consider other options that may allow HELCO to complete the installation of CT-4 and CT-5 (including seeking a land use reclassification of the Keahole site from the State Land Use Commission). If none of these options is ultimately successful and HELCO does not prevail on its appeal, HELCO may be unable to complete the installation of CT-4 and CT-5. The recovery of costs relating to CT-4 and CT-5 are subject to the rate-making process governed by the PUC. Management believes no adjustment to costs incurred to put CT-4 and CT-5 into service is required as of December 31, 2002. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HELCO may be required to write off a material portion of the costs incurred in its efforts to put these units into service whether or not CT-4 and CT-5 are installed. As of December 31, 2002, HELCO’s costs incurred in its efforts to put CT-4 and CT-5 into service and to support existing units (excluding costs the PUC permitted to be transferred to plant-in-service for pre-air permit facilities in HELCO’s most recent rate case) amounted to approximately $82 million, including $32 million for equipment and material purchases, $30 million for planning, engineering, permitting, site development and other costs and $20 million for AFUDC charged to the project prior to HELCO’s decision to discontinue the further accrual of AFUDC on CT-4 and CT-5. HELCO discontinued the accrual of AFUDC effective December 1, 1998, due in part to the delays and the potential for further delays. In addition to the $82 million in construction in progress, construction and/or purchase commitments related to CT-4 and CT-5 outstanding as of December 31, 2002 are estimated at approximately $0.6 million. See “HELCO Power Situation” in Note 3 of the “Notes to Consolidated Financial Statements.”

Kamoku-Pukele transmission line. HECO has for some time been expending efforts to address future potential line overloads in its two major corridors (Northern and Southern) transmitting bulk power to the Honolulu/East Oahu area, and to improve the reliability of the Pukele substation at the end of the Northern corridor. HECO planned to construct a part underground/part overhead 138 kv transmission line from the Kamoku substation to the Pukele substation in order to close the gap between the Southern and Northern transmission corridors and provide a third 138 kv transmission line to the Pukele substation. Construction of the Kamoku to Pukele transmission line in its proposed location required the BLNR to approve a Conservation District Use Permit (CDUP) for the overhead portion of the line that would have been in conservation district lands. On June 28, 2002, the BLNR issued a ruling denying HECO’s request for the CDUP.

HECO continues to believe that the proposed project is needed. HECO is evaluating alternative ways to accomplish the project, and possible future actions to expedite PUC review of the alternatives and the need for the project. As of December 31, 2002, the accumulated costs related to the Kamoku to Pukele transmission line amounted to $17 million, including $12 million for planning, engineering and permitting costs and $5 million for AFUDC. These costs are recorded in construction in progress. The recovery of costs relating to the Kamoku to Pukele transmission line project is subject to the rate-making process governed by the PUC. Management believes no adjustment to costs incurred to put the Kamoku to Pukele transmission line into service is required as of December 31, 2002. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HECO may be required to write off a material portion or all of the costs incurred in its efforts

25

to put the Kamoku to Pukele transmission line into service whether or not the line is installed. See “Oahu transmission system” in Note 3 of the “Notes to Consolidated Financial Statements.”

Bank

Regulation of ASB. ASB is subject to examination and comprehensive regulation by the OTS and the FDIC, and is subject to reserve requirements established by the Board of Governors of the Federal Reserve System. By reason of the regulation of its subsidiary, ASB Realty Corporation, ASB is also subject to regulation by the Hawaii Commissioner of Financial Institutions. Regulation by these agencies focuses in large measure on the adequacy of ASB’s capital and the results of periodic “safety and soundness” examinations conducted by the OTS.

Capital requirements. The OTS, which is ASB’s principal regulator, administers two sets of capital standards—minimum regulatory capital requirements and prompt corrective action requirements. The FDIC also has prompt corrective action capital requirements. As of December 31, 2002, ASB was in compliance with OTS minimum regulatory capital requirements and was “well-capitalized” within the meaning of OTS prompt corrective action regulations and FDIC capital regulations, as follows:

• ASB met applicable minimum regulatory capital requirements (noted in parentheses) at December 31, 2002 with a tangible capital ratio of 6.7% (1.5%), a core capital ratio of 6.7% (4.0%) and a total risk-based capital ratio of 14.7% (8.0%).

• ASB met the capital requirements to be generally considered “well-capitalized” (noted in parentheses) at December 31, 2002 with a leverage ratio of 6.7% (5.0%), a Tier-1 risk-based capital ratio of 13.5% (6.0%) and a total risk-based capital ratio of 14.7% (10.0%).

The purpose of the prompt corrective action capital requirements is to establish thresholds for varying degrees of oversight and intervention by regulators. Declines in levels of capital, depending on their severity, will result in increasingly stringent mandatory and discretionary regulatory consequences. Capital levels may decline for any number of reasons, including reductions that would result if there were losses from operations, deterioration in collateral values or the inability to dispose of real estate owned (such as by foreclosure) within five years. The regulators have substantial discretion in the corrective actions they might direct and could include restrictions on dividends and other distributions that ASB may make to its shareholders and the requirement that ASB develop and implement a plan to restore its capital. Under an agreement with regulators entered into by HEI when it acquired ASB, HEI could be required to contribute up to an additional $28 million, if necessary to maintain ASB’s capital position.

Examinations. ASB is subject to periodic “safety and soundness” examinations by the OTS. In conducting its examinations, the OTS utilizes the Uniform Financial Institutions Rating System adopted by the Federal Financial Institutions Examination Council, which system utilizes the “CAMELS” criteria for rating financial institutions. The six components in the rating system are: Capital adequacy, Asset quality, Management, Earnings, Liquidity and Sensitivity to market risk. The OTS examines and rates each CAMELS component. An overall CAMELS rating is also given, after taking into account all of the component ratings. A financial institution may be subject to formal regulatory or administrative direction or supervision such as a “memorandum of understanding” or a “cease and desist” order following an examination if its CAMELS rating is not satisfactory. An institution is prohibited from disclosing the OTS’s report of its safety and soundness examination or the component and overall CAMELS rating to any person or organization not officially connected with the institution as officer, director, employee, attorney, or auditor, except as provided by regulation.

The Federal Deposit Insurance Act, as amended, addresses the safety and soundness of the deposit insurance system, supervision of depository institutions and improvement of accounting standards. Pursuant to this Act, federal banking agencies have promulgated regulations that affect the operations of ASB and its holding companies (e.g., standards for safety and soundness, real estate lending, accounting and reporting, transactions with affiliates and loans to insiders). FDIC regulations restrict the ability of financial institutions that fail to meet relevant capital measures to engage in certain activities, such as offering interest rates on deposits that are significantly higher than the rates offered by competing institutions and offering “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 participant, not $100,000 per plan). As of December 31, 2002, ASB was “well-capitalized” and thus not subject to these restrictions.

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Qualified Thrift Lender status. In order to maintain its status as a “qualified thrift lender” (QTL), ASB is required to maintain at least 65% of its assets in “qualified thrift investments,” which include housing-related loans as well as certain small business loans, education loans, loans made through credit card accounts and a basket (not exceeding 20% of total assets) of other consumer loans and other assets. Savings associations that fail to maintain QTL status are subject to various penalties, including limitations on their activities. In ASB’s case, the activities of HEI, HEIDI and HEI’s other subsidiaries would also be subject to restrictions, and a failure or inability to comply with those restrictions could effectively result in the required divestiture of ASB.

Federal Thrift Charter. In November 1999, Congress passed the Gramm-Leach-Bliley Act of 1998 (the Gramm Act), under which banks, insurance companies and investment firms can compete directly against each other, thereby allowing “one-stop shopping” for an array of financial services. Although the Gramm Act further restricts the creation of so-called “unitary savings and loan holding companies” (i.e., companies such as HEI whose subsidiaries include one or more savings associations and one or more nonfinancial subsidiaries), the unitary savings and loan holding company relationship among HEI, HEIDI and ASB is “grandfathered” under the Gramm Act so that HEI and its subsidiaries will be able to continue to engage in their current activities so long as ASB maintains its QTL status. Under the Gramm Act, any proposed acquisition of ASB would have to satisfy applicable statutory and regulatory requirements and potential acquirers of ASB would most likely be limited to companies that are already qualified as, or capable of qualifying as, either a traditional savings and loan association holding company or a bank holding company, or as one of the newly authorized financial holding companies permitted under the Gramm Act.

Material estimates and critical accounting policies

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

Material estimates that are particularly susceptible to significant change in the case of the Company include the amounts reported for investment securities, allowance for loan losses, regulatory assets, pension and other postretirement benefit obligations, reserves for discontinued operations (see “Discontinued operations and asset dispositions” under “Certain factors that may affect future results and financial condition” above), current and deferred taxes, contingencies and litigation.

In accordance with SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” management has identified the 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.

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

Consolidated

Investment securities. Debt securities that the Company intends to and has the ability to hold to maturity are classified as held-to-maturity securities and reported at amortized cost. Marketable equity securities and debt securities that are bought and held principally for the purpose of selling them in the near term are classified as trading securities and reported at fair value, with unrealized gains and losses included in earnings. Marketable equity securities and debt securities not classified as either held-to-maturity or trading securities are classified as available-for-sale securities and reported at fair value, with unrealized gains and losses excluded from earnings and reported in a separate component of stockholders’ equity.

For securities that are not trading securities, declines in value determined to be other than temporary are included in earnings and result in a new cost basis for the investment. The specific identification method is used in determining realized gains and losses on the sales of securities.

ASB owns private-issue mortgage-related securities as well as mortgage-related securities issued by the Federal Home Loan Mortgage Corporation (FHLMC), Government National Mortgage Association (GNMA) and FNMA, all of which are classified as available-for-sale. Market prices for the private-issue mortgage-related securities are not readily available from standard pricing services, so prices are obtained from dealers who are

27

specialists in those markets. The prices of these securities may be influenced by factors such as market liquidity, corporate credit considerations of the underlying collateral, the levels of interest rates, expectations of prepayments and defaults, limited investor base, market sector concerns and overall market psychology. Adverse changes in any of these factors may result in additional losses. Market prices for the mortgage-related securities issued by FHLMC, GNMA and FNMA are available from most third party securities pricing services. ASB obtains market prices for these securities from a third party financial services provider. At December 31, 2002, ASB had mortgage-related securities issued by FHLMC, GNMA and FNMA valued at $1.9 billion and private-issue mortgage-related securities valued at $0.9 billion.

Because quoted market prices are not available, HEI’s income notes are valued by discounting the expected future cash flows using current market rates for similar investments by an outside party. The fair value of these securities may vary substantially from period to period because of changes in market interest rates and in the performance of the assets underlying such securities. At December 31, 2002, HEI had income notes valued at $8.0 million, compared to a valuation of these notes of $15.6 million at December 31, 2001.

Property, plant and equipment. Property, plant and equipment are reported at cost. Self-constructed electric 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 property, plant and equipment when construction is completed and the facilities are either placed in service or become useful for public utility purposes. Upon the retirement or sale of electric utility plant, no gain or loss is recognized. The cost of the plant retired or sold and the cost of removal (net of salvage value) previously provided through depreciation are charged to accumulated depreciation.

Management believes that the PUC will allow recovery of property, plant and equipment in its electric rates. If the PUC does not allow recovery of any such costs, the electric utility would be required to write off the disallowed costs at that time. See the discussion above concerning costs recorded in construction in progress for CT-4 and CT-5 at Keahole and the proposed Kamoku-Pukele transmission line under “Certain factors that may affect future results and financial condition–Other regulatory and permitting contingencies.”

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

The Company’s reported costs of providing retirement benefits (described in Note 8 in the “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 2002, 2001 and 2000 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 2002 and 2001, the Company recorded other postretirement benefit expense, net of amounts capitalized, of approximately $4 million and $2 million, respectively, in accordance with the provisions of SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” Actual payments of benefits made to retirees during 2002 and 2001 were $6 million and $7 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 2002 and 2001, the Company recorded non-cash pension income, net of amounts capitalized, of approximately $11 million and $17 million, respectively, and paid 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 considers the Moody’s Aa and Aaa Daily Long-Term Corporate Bond Yield Averages, as well as yields for 20 and 30 year

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Treasury strips. 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 8 in the “Notes to Consolidated Financial Statements,” the Company has revised key assumptions at December 31, 2002 compared to December 31, 2001. Such changes will not have an impact on reported costs in 2002; however, for future years, such changes will have a significant impact. Based upon the 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), the Company estimates that retirement benefits expense, net of amounts capitalized and income taxes, will be $12 million in 2003 as compared to net retirement benefits income of $4 million in 2002 (or $16 million less net income). Of the $12 million of net retirement benefits expense, it is projected that HECO and its subsidiaries will record an estimated $8 million in 2003 as compared to net retirement benefits income of $6 million in 2002 (or $14 million less net income). In determining the retirement benefit costs, these 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 associated with a change in certain actuarial assumptions by the indicated percentage and constitute “forward-looking statements.” While the tables below reflect an increase or decrease in the percentage for each assumption, the Company and its actuaries expect that the inverse of these changes would impact the projected benefit obligation (PBO) and 2003 net income in the opposite direction. 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 postretirement benefits plan.

Actuarial assumption	Change in assumption		Impact on PBO		Impact on 2003 net income
(in millions)
Pension benefits
Discount rate	(0.5	)%	$	51.8	$	(2.5	)
Rate of return on plan assets	(0.5	)		—		(1.4	)
Other benefits
Discount rate	(0.5	)		9.3		(0.2	)
Health care cost trend rate	0.5			2.0		(0.1	)
Rate of return on plan assets	(0.5	)		—		(0.2	)

As a result of its plan asset return experience in 2002, at December 31, 2002, the Company was required to recognize an additional minimum liability of $9 million as prescribed by SFAS No. 87. The liability was recorded partly as an intangible asset and partly as a reduction to common equity through a charge to other comprehensive income, and did not affect net income for 2002. The charge to other comprehensive income would be restored through common equity in future periods to the extent the fair value of trust assets exceeded the accumulated benefit obligation.

Environmental expenditures. 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. Liabilities are recorded when environmental assessments and/or remedial efforts are probable, and the cost can be reasonably estimated. Estimated costs are based upon an expected level of contamination and remediation efforts. Should the level of contamination and remediation efforts be different than initially expected, the ultimate costs will differ. See “Environmental regulation” in Note 3 of the “Notes to Consolidated Financial Statements” for a description of the Honolulu Harbor investigation.

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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.

Governmental tax authorities could challenge a tax return position taken by management, and such challenges might not be raised and finally resolved until several years after the events in question. If the Company’s position does not prevail, the Company’s results of operations and financial condition may be adversely affected as the related deferred or current income tax asset would be impaired.

In March 1998, ASB formed a subsidiary, ASB Realty Corporation, which elects to be taxed as a REIT. This reorganization has reduced Hawaii bank franchise taxes, net of federal income taxes, of HEIDI and ASB by $17 million for 2002 and prior years. The State of Hawaii Department of Taxation has challenged ASB’s position and has issued notices of tax assessment for 1999, 2000 and 2001. ASB believes that its tax position is proper and, in October 2002, filed an appeal with the State Board of Review, First Taxation District. No provision for Hawaii bank franchise taxes has been made since 1998. If the state’s position prevails, ASB would suffer adverse state income tax consequences. See Note 9 of the “Notes to Consolidated Financial Statements” for further information.

The Company’s loss of its investment in East Asia Power Resources Corporation of approximately $90 million was recognized in 2000 for financial reporting purposes and was included in HEI’s 2001 income tax return as an ordinary loss. HEI has requested that the Internal Revenue Service confirm that the treatment of this loss, as an ordinary loss, was proper.

Electric utility

Regulation by the PUC. The electric utility subsidiaries 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 and costs of HECO and its subsidiaries 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. As of December 31, 2002, regulatory assets amounted to $106 million. These regulatory assets are itemized in Note 3 of the “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 existing regulatory assets and rates in effect allow the utilities to earn a reasonable rate of return, management believes the existing regulatory assets 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 HECO and its subsidiaries’ operations currently satisfy the SFAS No. 71 criteria. However, if events or circumstances should change so that those criteria are no longer satisfied, management believes that a material adverse effect on the Company’s results of operations and financial position may result as regulatory assets would be charged to expense.

Electric utility revenues. Electric utility 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, 2002, 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, 2002, HECO and its subsidiaries had recognized $16 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. 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 $1.9 million (before interest) of the $8.5 million of integrated resource planning costs incurred from 1995 through 1998 and in 2001, and the PUC’s decision is pending on this matter. The Consumer Advocate has not stated its position on the recovery of the $1.5 million of integrated resource planning costs incurred from 1999 through 2000.

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The rate schedules of the electric utility subsidiaries 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 electric utilities’ 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. HECO and its subsidiaries believe that the energy cost adjustment clauses continue to be necessary. These clauses were continued in the most recent HELCO and MECO rate cases.

Bank

Allowance for loan losses. ASB maintains an allowance for loan losses that it believes is adequate to absorb estimated losses on all loans. The level of allowance for loan losses is based on a continuing assessment of existing risks in the loan portfolio, historical loss experience, changes in collateral values, and current and anticipated economic conditions. For business and commercial real estate loans, a risk rating system is used. Loans are rated based on the degree of risk at origination and periodically thereafter, as appropriate. A credit review department performs an evaluation of these loan portfolios to ensure compliance with the internal risk rating system and timeliness of rating changes. Adverse changes in any of the risk factors could result in higher charge-offs and loan loss provisions. When loans are deemed impaired, the amount of impairment is measured based on the present value of expected future cash flows discounted at the loan’s effective interest rate and the fair value of the collateral securing the loan. Impairment losses are charged to the provision for loan losses and included in the allowance for loan losses.

For the remaining loans receivable portfolio, allowance for loan loss allocations are determined based on a loss migration analysis. The loss migration analysis determines potential loss factors based on historical loss experience for homogeneous loan portfolios.

At December 31, 2002, ASB’s allowance for loan losses was $45.4 million and ASB had $15.8 million of loans on nonaccrual status (in general, delinquent more than 90 days). In 2002, ASB’s provision for loan losses was $9.8 million.

Quantitative and Qualitative Disclosures about Market Risk

The Company manages various market risks in the ordinary course of business, including credit risk and liquidity risk, and believes its exposures to these risks are not material as of December 31, 2002. Because the Company does not have a portfolio of trading assets, the Company is not exposed to market risk from trading activities.

The Company is exposed to some commodity price risk primarily related to its fuel supply and IPP contracts and foreign currency exchange rate risk. The Company’s commodity price risk is mitigated by the electric utilities’ energy cost adjustment clauses in their rate schedules. The Company’s remaining investment in the Philippines as of December 31, 2002 is the investment in 22% of the common stock of CEPALCO, which the Company has available for sale. The sale price may be affected by the Philippine Peso/U.S. dollar exchange rate. The Company currently has no hedges against its commodity price risk and foreign currency exchange rate risks.

The Company considers interest rate risk to be a very significant market risk as it could potentially have a significant effect on the Company’s results of operations and financial condition especially as it relates to ASB. Interest rate risk can be defined as the exposure of the Company’s earnings to adverse movements in interest rates.

HEI has entered into two swap agreements to manage its exposure to interest rate risk. In general, HEI issues primarily fixed-rate long-term debt to balance its short-term debt, which in essence is variable-rate debt by virtue of its short-term nature. In April 2000, during a period of rising interest rates, HEI was able to issue $100 million of its variable-rate medium-term notes and simultaneously enter into a swap agreement, which effectively fixed the interest rate on the $100 million of debt at 7.995% until maturity in April 2003. In June 2001, during a period of falling interest rates, HEI had the opportunity to lower its interest payments on these same medium-term notes and entered into a swap agreement which changed $100 million of effectively 7.995% fixed-rate debt to variable-rate

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debt (adjusted quarterly based on changes in the London InterBank Offered Rate (LIBOR) indices). Other than these swaps, the Company does not currently use derivatives to manage interest rate risk.

Bank

The Company’s success is dependent, in part, upon ASB’s ability to manage interest rate risk. For ASB, interest-rate risk is the sensitivity of net interest income and the market value of interest-sensitive assets and liabilities to changes in interest rates. The primary source of interest-rate risk is the mismatch in timing between the maturity or repricing of interest-sensitive assets and liabilities. Large mismatches could adversely affect ASB’s earnings and the market value of its interest-sensitive assets and liabilities in the event of significant changes in the level of interest rates.

ASB’s Asset/Liability Management Committee (ALCO) serves as the group charged with the responsibility of managing interest rate risk and of carrying out the overall asset/liability management objectives and activities of ASB as approved by the ASB Board of Directors. ALCO establishes policies that monitor and coordinate ASB’s assets and liabilities.

ASB’s interest-rate risk profile is strongly influenced by the bank’s primary business of making fixed-rate residential mortgage loans and taking in retail deposits. The fixed-rate residential mortgage loans originated and retained by ASB are characterized by fixed interest rates and long average lives, but also have the potential to prepay at any time without penalty. The option to prepay is usually exercised by borrowers in low interest rate environments, significantly shortening the average lives of these assets. A majority of ASB’s liabilities consists of retail deposits. The interest rates paid on many of the retail deposit accounts can be adjusted in response to changes in market interest rates. Other retail deposit accounts with fixed interest rates typically have stated maturities much shorter than that of a 30-year mortgage. As a result, these liabilities will tend to reprice more frequently than the fixed-rate mortgage assets.

The typical result of this combination of assets and liabilities is to create a “liability sensitive” interest rate risk profile. In a rising interest-rate environment, the average rate on ASB’s liabilities will tend to increase faster than the average rate on the assets, causing a reduction in net interest spread and net interest income. In a falling interest-rate environment, the opposite happens: the average rate on the bank’s liabilities will tend to decrease faster than the average rate on the bank’s assets, causing an increase in net interest spread and net interest income. This volatility in net interest spread and net interest income represents one measure of interest rate risk, and the degree of volatility is dependent on the magnitude of the mismatch in the amount and timing of maturing or repricing interest-sensitive assets and interest-sensitive liabilities.

Since ASB’s primary business of making fixed-rate residential real estate loans and taking in retail deposits does not always result in the optimum mix of assets and liabilities for the management of net interest income and interest rate risk, other tools must be employed. Chief among these is use of the investment portfolio to secure asset types that may not be available in significant amounts through originations. Included in this area are adjustable-rate mortgage-related securities, floating LIBOR-based securities, balloon or 15-year mortgage-related securities, and short average life collateralized mortgage obligations (CMOs). On the liability side, a shortage of retail deposits in desired maturities is made up through FHLB advances and other borrowings to meet asset/liability management needs.

Use of investments, FHLB advances and securities sold under agreements to repurchase, while efficient, is not as profitable as ASB’s own lending and deposit taking activities. In this regard, ASB is building its portfolio of consumer, business banking and commercial real estate loans, which generally earn higher rates of interest and have maturities shorter than residential real estate loans. The origination of consumer, business banking and commercial real estate loans involves risks different from those associated with originating residential real estate loans. For example, credit risk associated with consumer, business banking and commercial real estate loans is generally higher than for mortgage loans, the sources and level of competition may be different and, compared to residential real estate lending, the making of business banking and commercial real estate loans is a relatively new business for ASB. These different risk factors are considered in the underwriting and pricing standards established by ASB for its consumer, business banking and commercial real estate loans.

ASB currently does not use any interest-rate derivatives to manage interest-rate risk.

Management measures interest-rate risk using simulation analysis with an emphasis on measuring changes in net interest income and the market value of interest-sensitive assets and liabilities in different interest-rate

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environments. The simulation analysis is performed using a dedicated asset/liability management software system. During the year, the bank upgraded its systems and purchased a new asset/liability management system enhanced with a mortgage prepayment model and a CMO database. The new simulation software is capable of generating scenario-specific cash flows for all instruments using the specified contractual information for each instrument and product specific prepayment assumptions. This new software has enhanced the bank’s ability to perform net interest income and market value sensitivity analysis. Accordingly, ASB has changed its market risk analysis from a tabular presentation to a presentation of net interest income and market value sensitivity. HEI has also changed the market risk analysis for its other segments from a tabular presentation to a presentation of net interest expense sensitivity.

Net interest income (NII) sensitivity analysis measures the change in ASB’s twelve-month, pre-tax NII in alternate interest rate scenarios. NII sensitivity is measured as the change in NII in alternative interest-rate scenarios as a percentage of the base case NII. The base case interest-rate scenario is established using the current yield curve and assumes interest rates remain constant over the next twelve months. The alternate scenarios are created by assuming immediate and sustained parallel shocks of the yield curve in increments of +/- 100 basis points. The simulation model forecasts scenario-specific principal and interest cash flows for the interest-bearing assets and liabilities, and the NII is calculated for each scenario. Key balance sheet modeling assumptions used in the NII sensitivity analysis include: the size of the balance sheet remains relatively constant over the simulation horizon and maturing assets or liabilities are reinvested in similar instruments in order to maintain the current mix of the balance sheet. In addition, assumptions are made about the prepayment behavior of mortgage-related assets and the pricing characteristics of new assets and liabilities. The simulation does not contemplate any actions that ASB management might undertake in response to changes in interest rates. These assumptions are used for analytical purposes only and do not represent management’s views of future market movements or future earnings. Rather, these assumptions are intended to help management identify potential exposures in ASB’s current balance sheet and formulate appropriate strategies for managing interest rate risk.

ASB’s net portfolio value (NPV) ratio is a measure of the economic capitalization of the bank. The NPV ratio is the ratio of the net portfolio value of ASB to the present value of expected net cash flows from existing assets. Net portfolio value represents the theoretical market value of ASB’s net worth and is defined as the present value of expected net cash flows from existing assets minus the present value of expected cash flows from existing liabilities plus the present value of expected net cash flows from existing off-balance sheet contracts. The NPV ratio is calculated by ASB pursuant to guidelines established by the OTS in Thrift Bulletin 13a. Key assumptions used in the calculation of ASB’s NPV ratio include the prepayment behavior of loans and investments, the possible distribution of future interest rates, future pricing spreads for assets and liabilities and the rate and balance behavior of deposit accounts with indeterminate maturities. Typically, if the value of the bank’s assets grows relative to the value of the bank’s liabilities, the NPV ratio will increase. Conversely, if the value of the bank’s liabilities grows relative to the value of the bank’s assets, the NPV ratio will decrease. The NPV ratio is calculated in multiple scenarios. As with the NII simulation, the base case is represented by the current yield curve. Alternate scenarios are created by assuming immediate parallel shifts in the yield curve in increments of +/- 100 basis points.

The NPV ratio sensitivity measure is the change from the NPV ratio calculated in the base case to the NPV ratio calculated in the alternate rate scenarios. In general, high sensitivity measures, or large decreases in the NPV ratio, are indicative of large imbalances between the maturity or repricing of interest sensitive assets and interest sensitive liabilities. Low NPV ratio sensitivity measures, or small decreases in the NPV ratio, are indicative of a better match between the timing and amount of the maturity or repricing of assets and liabilities. The sensitivity measure alone is not necessarily indicative of the interest-rate risk of an institution, as institutions with high levels of capital may be able to support a high sensitivity measure. This measure is evaluated in conjunction with the NPV ratio calculated in each scenario.

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ASB’s interest-rate risk sensitivity measures as of December 31, 2002 and 2001 constitute “forward-looking statements” and were as follows:

December 31	2002						2001
	Change in NII		NPV ratio		NPV ratio sensitivity (change from base case in basis points)		Change in NII		NPV ratio	NPV ratio sensitivity (change from base case in basis points)
Change in interest rates (basis points)
+300	1.9	%	7.90	%	(235	)	(4.5	)	6.10	(367	)
+200	3.0		9.15		(110	)	(3.0	)	7.45	(232	)
+100	3.3		10.01		(24	)	(1.5	)	8.60	(117	)
Base	—		10.25		—		—		9.77	—
-100	(5.7	)	10.02		(23	)	2.2		10.65	88

Management believes that ASB’s interest-rate risk position at December 31, 2002 represents a reasonable level of risk.

In the past, ASB’s NII profile has shown NII increasing in the falling rate scenarios and decreasing in the rising rate scenarios. That profile is typical of an institution that is “liability sensitive.” The current NII profile differs slightly – the bank is “asset-sensitive” over small changes in interest rates (< 100 basis points), and becomes “liability-sensitive” over larger changes in interest rates. This profile is due to the extremely low level of interest rates and fast prepayment speeds anticipated in the current interest rate environment. In the base case, the low level of interest rates causes the prepayment models to forecast very fast prepayment speeds for the mortgage assets. The high volume of repayments is assumed to be reinvested at the current, low level of interest rates, which causes the overall yield of the mortgage assets to decrease quickly. In the –100 basis point scenario, NII drops relative to the base case, as even faster prepayment forecasts and lower reinvestment rates cause the yield on mortgage assets to decline faster than in the base case. The yield on liabilities, however, does not fall as rapidly, as the low level of interest rates limits the ability to lower the rate on retail deposits. This causes net interest income to fall.

The NII increases in the +100 basis point scenario as slower prepayment speeds enable the mortgage assets to maintain their yield. The increase in interest income is slightly greater than the increase in interest expense and results in a slight improvement in the 12-month estimate of net interest income compared to the base case. In the +200 and +300 basis point scenarios, the profile becomes more like that of a “liability sensitive” institution. In these scenarios, slower prepayment speeds continue to reduce the runoff of the existing mortgage assets, which reduces the amount available for reinvestment at the higher market rates. This constrains the speed with which the yield on the mortgage asset portfolio can adjust upwards to market levels. At the same time, the yield on the liabilities continues to increase with each increase in the level of interest rates.

The computation of the prospective effects of hypothetical interest rate changes is based on numerous assumptions, including relative levels of market interest rates, loan prepayments, actual balance changes and pricing strategies, and should not be relied upon as indicative of future results. Furthermore, to the extent market conditions and other factors vary from the assumptions used in the simulation analysis, future results will differ from the simulation results.

The table below provides contractual balances of ASB’s on- and off-balance sheet financial instruments at the expected maturity dates as well as the estimated fair values of those on- and off-balance sheet financial instruments as of December 31, 2001 and constitutes “forward-looking statements.” The expected maturity categories take into consideration historical prepayment rates as well as actual amortization of principal and do not take into consideration reinvestment of cash. Various prepayment rates ranging from 12% to 47% were used in computing the expected maturity of ASB’s interest-sensitive assets as of December 31, 2001. The expected maturity categories for interest-sensitive core deposits take into consideration historical attrition rates based on core deposit studies. Core deposit attrition rates ranging from 14% to 32% were used in expected maturity computations for core deposits. Actual prepayment and attrition rates may differ from expected rates and may cause the actual maturities and principal repayments to differ from the expected maturities and principal repayments. The weighted-average interest rates for the various assets and liabilities presented are as of December 31, 2001. See Note 14 in

34

the “Notes to Consolidated Financial Statements” for descriptions of the methods and assumptions used to estimate fair value of each applicable class of financial instruments.

December 31, 2001	Expected maturity/principal repayment
(in millions)	2002		2003		2004		2005		2006		There- after		Total		Estimated fair value
Interest-sensitive assets
Mortgage loans and Mortgage-related securities
Adjustable rate	$	521	$	344	$	228	$	151	$	100	$	192	$	1,536	$	1,568
Average interest rate (%)		6.1		6.0		6.0		5.9		5.9		5.9		6.0
Fixed rate—one-to-four family residential		535		343		265		225		196		1,498		3,062		3,107
Average interest rate (%)		7.4		7.1		6.9		6.8		6.8		6.7		6.9
Fixed rate—multi-family residential and nonresidential		20		22		24		26		28		61		181		199
Average interest rate (%)		7.6		7.6		7.6		7.6		7.6		7.5		7.6
Consumer loans		76		57		43		54		14		—		244		254
Average interest rate (%)		9.1		9.5		9.9		8.8		11.2		—		9.4
Commercial loans		2		2		3		88		94		—		189		193
Average interest rate (%)		6.0		6.0		6.0		5.8		6.2		—		6.0
Interest-bearing deposits		319		—		—		—		—		—		319		319
Average interest rate (%)		1.7		—		—		—		—		—		1.7
Interest-sensitive liabilities
Passbook deposits		244		120		104		89		77		471		1,105		1,105
Average interest rate (%)		1.5		1.5		1.5		1.5		1.5		1.5		1.5
NOW and other demand deposits		168		127		98		76		59		242		770		770
Average interest rate (%)		0.2		0.2		0.2		0.2		0.2		0.2		0.2
Money market accounts		108		74		50		34		23		49		338		338
Average interest rate (%)		1.8		1.8		1.8		1.8		1.8		1.8		1.8
Certificates of deposit		951		105		114		222		58		17		1,467		1,490
Average interest rate (%)		3.8		4.2		5.8		6.4		5.9		4.7		4.4
FHLB advances		173		253		264		309		34		—		1,033		1,079
Average interest rate (%)		3.9		5.0		5.4		6.5		6.9		—		5.4
Other borrowings		648		—		35		—		—		—		683		685
Average interest rate (%)		2.7		—		4.7		—		—		—		2.8
Interest-sensitive off-balance sheet items
Loans serviced for others														1,057		13
Average interest rate (%)														6.7
Loan commitments and loans in process														64		(1	)
Average interest rate (%)														6.5
Unused lines and letters of credit														662		22
Average interest rate (%)														11.2

35

Other than bank

The Company’s general policy is to manage “other than bank” interest rate risk through use of a combination of short-term debt, long-term debt (primarily fixed-rate debt) and preferred securities. Net interest expense sensitivity analysis measures the change from the base case in twelve-month, pre-tax net interest expense in alternate interest rate scenarios. The base case interest-rate scenario is established using the current yield curve and assumes interest rates remain constant over the next twelve months. The alternate scenarios are created by assuming immediate and sustained parallel shocks of the yield curve in increments of +/- 100 basis points. The Company forecasts interest cash flows for the nonfixed-rate interest-bearing assets and liabilities (and assumes no changes in balances from December 31, except for $100 million of variable-rate debt that is expected to be refinanced to fixed-rate debt upon its maturity on April 15, 2003) and calculates net interest expense for each scenario. The calculation does not contemplate any actions that management might undertake in response to changes in interest rates. These assumptions are used for analytical purposes only and do not represent management’s views of future market movements or future earnings.

The Company’s “other than bank” interest rate risk sensitivity measure as of December 31, 2002 and 2001 constitutes “forward-looking statements” and was as follows:

December 31	2002			2001
(in millions)	Change in net interest expense
Change in interest rates (basis points)
+300	$	0.4		$	2.4
+200		0.3			1.6
+100		0.1			0.8
- 100		(0.1	)		(0.8	)

The table below provides, on a tabular basis, information about the Company’s “other than bank” market sensitive financial instruments, including contractual balances at the stated maturity dates as well as the estimated fair values as of December 31, 2001, and constitutes “forward-looking statements.”

December 31, 2001	Expected maturity
(in millions)	2002		2003		2004		2005		2006		There- after		Total		Estimated fair value
Interest-sensitive liabilities
Long-term debt – variable rate	$	—	$	100	$	—	$	—	$	—	$	—	$	100	$	101
Average interest rate (%)		—		6.2		—		—		—		—		6.2
Long-term debt – fixed rate		74		36		1		37		110		788		1,046		1,013
Average interest rate (%)		6.8		6.7		6.8		6.7		7.5		6.0		6.2
HEI- and HECO-obligated preferred securities of trust subsidiaries		—		—		—		—		—		200		200		202
Average distribution rate (%)		—		—		—		—		—		8.0		8.0

36

Independent Auditors’ Report

The Board of Directors and Stockholders

Hawaiian Electric Industries, Inc.:

We have audited the accompanying consolidated balance sheets of Hawaiian Electric Industries, Inc. and subsidiaries as of December 31, 2002 and 2001, 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, 2002. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Hawaiian Electric Industries, Inc. and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

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.

Honolulu, Hawaii

January 20, 2003

37

Consolidated Statements of Income

Hawaiian Electric Industries, Inc. and Subsidiaries

Years ended December 31	2002			2001			2000
(in thousands, except per share amounts)
Revenues
Electric utility	$	1,257,176		$	1,289,304		$	1,277,170
Bank		399,255			444,602			450,882
Other		(2,730	)		(6,629	)		4,259
		1,653,701			1,727,277			1,732,311
Expenses
Electric utility		1,062,220			1,095,359			1,084,079
Bank		306,372			362,503			380,841
Other		18,676			13,242			9,858
		1,387,268			1,471,104			1,474,778
Operating income (loss)
Electric utility		194,956			193,945			193,091
Bank		92,883			82,099			70,041
Other		(21,406	)		(19,871	)		(5,599	)
		266,433			256,173			257,533
Interest expense—other than bank		(72,292	)		(78,726	)		(77,298	)
Allowance for borrowed funds used during construction		1,855			2,258			2,922
Preferred stock dividends of subsidiaries		(2,006	)		(2,006	)		(2,007	)
Preferred securities distributions of trust subsidiaries		(16,035	)		(16,035	)		(16,035	)
Allowance for equity funds used during construction		3,954			4,239			5,380
Income from continuing operations before income taxes		181,909			165,903			170,495
Income taxes		63,692			58,157			61,159
Income from continuing operations		118,217			107,746			109,336
Discontinued operations, net of income taxes
Loss from operations		—			(1,254	)		(63,592	)
Net loss on disposals		—			(22,787	)		—
Loss from discontinued operations		—			(24,041	)		(63,592	)
Net income	$	118,217		$	83,705		$	45,744
Basic earnings (loss) per common share
Continuing operations	$	3.26		$	3.19		$	3.36
Discontinued operations		—			(0.71	)		(1.95	)
	$	3.26		$	2.48		$	1.41
Diluted earnings (loss) per common share
Continuing operations	$	3.24		$	3.18		$	3.35
Discontinued operations		—			(0.71	)		(1.95	)
	$	3.24		$	2.47		$	1.40
Dividends per common share	$	2.48		$	2.48		$	2.48
Weighted-average number of common shares outstanding		36,278			33,754			32,545
Dilutive effect of stock options and dividend equivalents		199			188			142
Adjusted weighted-average shares		36,477			33,942			32,687

See accompanying “Notes to Consolidated Financial Statements.”

38

Consolidated Balance Sheets

Hawaiian Electric Industries, Inc. and Subsidiaries

December 31				2002					2001
(in thousands)
ASSETS
Cash and equivalents				$	244,525				$	450,827
Accounts receivable and unbilled revenues, net					176,327					164,124
Available-for-sale investment and mortgage-related securities					1,960,288					1,613,710
Available-for-sale mortgage-related securities pledged for repurchase agreements					784,362					756,749
Held-to-maturity investment securities (estimated fair value $89,545 and $84,211)					89,545					84,211
Loans receivable, net					2,993,989					2,857,622
Property, plant and equipment, net
Land	$	45,212				$	45,005
Plant and equipment		3,297,357					3,178,822
Construction in progress		174,122					176,655
		3,516,691					3,400,482
Less — accumulated depreciation		(1,437,366	)		2,079,325		(1,332,979	)		2,067,503
Regulatory assets					105,568					111,376
Other					345,002					309,867
Goodwill and other intangibles					97,572					101,954
				$	8,876,503				$	8,517,943
LIABILITIES AND STOCKHOLDERS’ EQUITY
Liabilities
Accounts payable				$	134,416				$	119,850
Deposit liabilities					3,800,772					3,679,586
Securities sold under agreements to repurchase					667,247					683,180
Advances from Federal Home Loan Bank					1,176,252					1,032,752
Long-term debt					1,106,270					1,145,769
Deferred income taxes					235,431					185,436
Contributions in aid of construction					218,094					213,557
Other					257,315					293,742
					7,595,797					7,353,872
HEI- and HECO-obligated preferred securities of trust subsidiaries directly or indirectly holding solely HEI and HEI-guaranteed and HECO and HECO-guaranteed subordinated debentures					200,000					200,000
Preferred stock of subsidiaries – not subject to mandatory redemption					34,406					34,406
					234,406					234,406
Stockholders’ equity
Preferred stock, no par value, authorized 10,000 shares; issued: none					—					—
Common stock, no par value, authorized 100,000 shares; issued and outstanding: 36,809 shares and 35,600 shares					839,503					787,374
Retained earnings					176,118					147,837
Accumulated other comprehensive income (loss)
Net unrealized gains (losses) on securities	$	35,914				$	(5,181	)
Minimum pension liability		(5,235	)		30,679		(365	)		(5,546	)
					1,046,300					929,665
				$	8,876,503				$	8,517,943

See accompanying “Notes to Consolidated Financial Statements.”

39

Consolidated Statements of Changes in Stockholders’ Equity

Hawaiian Electric Industries, Inc. and Subsidiaries

					Retained earnings			Accumulated other comprehensive income (loss)			Total
	Common stock
(in thousands)	Shares	Amount
Balance, December 31, 1999	32,213	$	665,614		$	182,251		$	(279	)	$	847,586
Comprehensive income:
Net income	—		—			45,744			—			45,744
Net unrealized gains on securities arising during the period, net of taxes of $69	—		—			—			129			129
Minimum pension liability adjustment, net of tax benefits of $25	—		—			—			(40	)		(40	)
Comprehensive income	—		—			45,744			89			45,833
Issuance of common stock:
Dividend reinvestment and stock purchase plan	511		17,615			—			—			17,615
Retirement savings and other plans	267		8,704			—			—			8,704
Expenses and other	—		(8	)		—			—			(8	)
Common stock dividends ($2.48 per share)	—		—			(80,671	)		—			(80,671	)
Balance, December 31, 2000	32,991		691,925			147,324			(190	)		839,059
Comprehensive income:
Net income	—		—			83,705			—			83,705
Net unrealized losses on securities:
Cumulative effect of the adoption of SFAS No. 133, net of tax benefits of $1,294	—		—			—			(559	)		(559	)
Net unrealized losses arising during the period, net of taxes of $3,618	—		—			—			(1,748	)		(1,748	)
Add: reclassification adjustment for net realized gains included in net income, net of taxes of $1,391	—		—			—			(3,003	)		(3,003	)
Minimum pension liability adjustment, net of tax benefits of $29	—		—			—			(46	)		(46	)
Comprehensive income (loss)	—		—			83,705			(5,356	)		78,349
Issuance of common stock:
Public offering	1,500		56,550			—			—			56,550
Dividend reinvestment and stock purchase plan	694		26,310			—			—			26,310
Retirement savings and other plans	415		14,816			—			—			14,816
Expenses and other	—		(2,227	)		—			—			(2,227	)
Common stock dividends ($2.48 per share)	—		—			(83,192	)		—			(83,192	)
Balance, December 31, 2001	35,600		787,374			147,837			(5,546	)		929,665
Comprehensive income:
Net income	—		—			118,217			—			118,217
Net unrealized gains on securities:
Net unrealized gains arising during the period, net of taxes of $14,465	—		—			—			38,346			38,346
Add: reclassification adjustment for net realized losses included in net income, net of tax benefits of $1,440	—		—			—			2,749			2,749
Minimum pension liability adjustment, net of tax benefits of $2,701	—		—			—			(4,870	)		(4,870	)
Comprehensive income	—		—			118,217			36,225			154,442
Issuance of common stock:
Dividend reinvestment and stock purchase plan	663		28,507			—			—			28,507
Retirement savings and other plans	546		21,407			—			—			21,407
Expenses and other	—		2,215			—			—			2,215
Common stock dividends ($2.48 per share)	—		—			(89,936	)		—			(89,936	)
Balance, December 31, 2002	36,809	$	839,503		$	176,118		$	30,679		$	1,046,300

At December 31, 2002, Hawaiian Electric Industries, Inc. (HEI) had reserved a total of 8,798,249 shares of common stock for future issuance under the HEI Dividend Reinvestment and Stock Purchase Plan, the Hawaiian Electric Industries Retirement Savings Plan, the 1987 Stock Option and Incentive Plan, as amended, and other plans.

See accompanying “Notes to Consolidated Financial Statements.”

40

Consolidated Statements of Cash Flows

Hawaiian Electric Industries, Inc. and Subsidiaries

Years ended December 31	2002			2001			2000
(in thousands)
Cash flows from operating activities
Income from continuing operations	$	118,217		$	107,746		$	109,336
Adjustments to reconcile income from continuing operations to net cash provided by operating activities
Depreciation of property, plant and equipment		115,597			110,425			108,608
Other amortization		25,396			19,119			10,214
Provision for loan losses		9,750			12,500			13,050
Writedowns of income notes		4,499			14,815			5,838
Deferred income taxes		35,197			382			7,142
Allowance for equity funds used during construction		(3,954	)		(4,239	)		(5,380	)
Changes in assets and liabilities, net of effects from the disposal of businesses
Decrease (increase) in accounts receivable and unbilled revenues, net		(12,203	)		23,932			(34,709	)
Increase (decrease) in accounts payable		14,566			(5,869	)		8,776
Increase (decrease) in taxes accrued		(38,419	)		(6,761	)		59,302
Changes in other assets and liabilities		(24,265	)		(12,624	)		(17,251	)
Net cash provided by operating activities.		244,381			259,426			264,926
Cash flows from investing activities
Available-for-sale mortgage-related securities purchased		(1,605,672	)		(1,190,130	)		(56,567	)
Principal repayments on available-for-sale mortgage-related securities		1,182,796			605,428			55
Proceeds from sale of mortgage-related securities		77,264			701,343			—
Held-to-maturity investment securities purchased		—			—			(56,500	)
Proceeds from maturities of held-to-maturity investment securities		—			—			43,000
Proceeds from sale of investment securities		—			87,528			—
Held-to-maturity mortgage-related securities purchased		—			—			(320,102	)
Principal repayments on held-to-maturity mortgage-related securities		—			—			281,169
Loans receivable originated and purchased		(1,210,082	)		(1,036,073	)		(530,133	)
Principal repayments on loans receivable		949,262			749,378			446,647
Proceeds from sale of loans		110,465			215,888			52,328
Proceeds from sale of real estate acquired in settlement of loans		12,013			9,821			15,701
Capital expenditures		(128,082	)		(126,308	)		(134,576	)
Contributions in aid of construction		11,042			10,958			8,484
Other		(278	)		(293	)		1,270
Net cash provided by (used in) investing activities		(601,272	)		27,540			(249,224	)
Cash flows from financing activities
Net increase in deposit liabilities		121,186			94,940			92,991
Net decrease in short-term borrowings with original maturities of three months or less		—			(101,402	)		(50,431	)
Proceeds from other short-term borrowings		—			—			57,499
Repayment of other short-term borrowings		—			(3,000	)		(55,682	)
Net increase in retail repurchase agreements		12,180			6,870			8,575
Proceeds from securities sold under agreements to repurchase		1,086,531			824,692			677,677
Repayments of securities sold under agreements to repurchase		(1,116,148	)		(744,236	)		(753,525	)
Proceeds from advances from Federal Home Loan Bank		350,100			214,100			511,931
Principal payments on advances from Federal Home Loan Bank		(206,600	)		(430,600	)		(451,760	)
Proceeds from issuance of long-term debt		35,275			117,336			187,507
Repayment of long-term debt		(64,500	)		(60,500	)		(76,500	)
Preferred securities distributions of trust subsidiaries		(16,035	)		(16,035	)		(16,035	)
Net proceeds from issuance of common stock		32,451			78,937			14,080
Common stock dividends		(73,412	)		(67,015	)		(68,624	)
Other		(9,742	)		(10,659	)		(650	)
Net cash provided by (used in) financing activities		151,286			(96,572	)		77,053
Net cash provided by (used in) discontinued operations		(697	)		47,650			(77,371	)
Net increase (decrease) in cash and equivalents		(206,302	)		238,044			15,384
Cash and equivalents, January 1		450,827			212,783			197,399
Cash and equivalents, December 31	$	244,525		$	450,827		$	212,783

See accompanying “Notes to Consolidated Financial Statements.”

41

Notes to Consolidated Financial Statements

1 • Summary of significant accounting policies

General

HEI is a holding company with wholly-owned subsidiaries engaged in electric utility, banking and other businesses, primarily in the State of Hawaii. In December 2000, HEI wrote off its indirect investment in East Asia Power Resources Corporation (EAPRC), an independent power producer in the Philippines, and in October 2001, HEI adopted a plan to exit the international power business. In November 1999, an HEI subsidiary, Hawaiian Tug & Barge Corp. (HTB), sold Young Brothers, Limited (YB) and substantially all of HTB’s operating assets. HTB’s name was changed to The Old Oahu Tug Service, Inc. (TOOTS) and it ceased operations. In September 1998, HEI adopted a plan to exit the residential real estate development business.

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

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

Consolidation. The consolidated financial statements include the accounts of HEI and its subsidiaries (collectively, the Company). All significant intercompany accounts and transactions have been eliminated in consolidation.

Cash and equivalents. The Company considers cash on hand, deposits in banks, deposits with the Federal Home Loan Bank (FHLB) of Seattle, money market accounts, certificates of deposit, short-term commercial paper and reverse repurchase agreements and liquid investments (with original maturities of three months or less) to be cash and equivalents.

Investment securities. Debt securities that the Company intends to and has the ability to hold to maturity are classified as held-to-maturity securities and reported at amortized cost. Marketable equity securities and debt securities that are bought and held principally for the purpose of selling them in the near term are classified as trading securities and reported at fair value, with unrealized gains and losses included in earnings. Marketable equity securities and debt securities not classified as either held-to-maturity or trading securities are classified as available-for-sale securities and reported at fair value, with unrealized gains and losses excluded from earnings and reported on a net basis in a separate component of stockholders’ equity.

For securities that are not trading securities, declines in value determined to be other than temporary are included in earnings and result in a new cost basis for the investment. The specific identification method is used in determining realized gains and losses on the sales of securities.

Derivative instruments and hedging activities. Derivatives are recognized at fair value in the balance sheet as an asset or liability. Changes in fair value of derivative instruments not designated as hedging instruments are (and the ineffective portions of hedges, if any in the future, would be) recognized in earnings in the current period. In the future, any changes in the fair value of a derivative designated as a fair value hedge and the hedged item would be recorded in earnings. Also, for a derivative designated as a cash flow hedge, the effective portion of changes in fair value of the derivative would be reported in other comprehensive income and subsequently would be reclassified into earnings when the hedged item affects earnings.

Statement of Financial Accounting Standards (SFAS) No. 133, as amended, allowed the reclassification of certain debt securities from held-to-maturity to either available-for-sale or trading at the time of adoption. On January 1, 2001, approximately $2 billion in mortgage-related securities and $13 million in investment securities having estimated fair values of approximately $2 billion and $13 million, respectively, were reclassified from held-to-maturity to available-for-sale. At January 1, 2001, the net unrealized loss on securities, net of income taxes, was included in accumulated other comprehensive income within stockholders’ equity.

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Equity method. Investments in up to 50%-owned affiliates for which the Company has the ability to exercise significant influence over the operating and financing policies, are accounted for under the equity method, whereby the investment is carried at cost, plus (or minus) the Company’s equity in undistributed earnings (or losses) since acquisition. Equity in earnings or losses are reflected in operating revenues.

Property, plant and equipment. Property, plant and equipment are reported at cost. Self-constructed electric 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 property, plant and equipment when construction is completed and the facilities are either placed in service or become useful for public utility purposes. Upon the retirement or sale of electric utility plant, no gain or loss is recognized. The cost of the plant retired or sold and the cost of removal (net of salvage value) previously provided through depreciation are charged to accumulated depreciation.

Depreciation. Depreciation is computed primarily using the straight-line method over the estimated useful lives of the assets being depreciated. Electric utility plant has useful lives ranging from 20 to 45 years for production plant, from 25 to 50 years for transmission and distribution plant and from 8 to 45 years for general plant. The electric utility subsidiaries’ composite annual depreciation rate was 3.9% in 2002, 2001 and 2000.

Retirement benefits. Pension and other postretirement benefit costs/(returns) are charged/(credited) primarily to expense and electric utility plant. The Company’s policy is to fund pension costs in amounts consistent with the requirements of the Employee Retirement Income Security Act of 1974. Certain health care and/or life insurance benefits are provided to eligible retired employees and the employees’ beneficiaries and covered dependents.

Environmental expenditures. The Company is subject to numerous federal and state environmental statutes and regulations. In general, environmental contamination treatment costs are charged to expense, unless it is probable that the Public Utilities Commission of the State of Hawaii (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. Environmental costs are either capitalized or charged to expense when environmental assessments and/or remedial efforts are probable and the cost can be reasonably estimated.

Financing costs. HEI uses the effective interest method to amortize the financing costs of the holding company over the term of the related long-term debt.

Hawaiian Electric Company, Inc. (HECO) and its subsidiaries use the straight-line method to amortize financing costs and premiums or discounts over the term of the related long-term debt. Unamortized financing costs and premiums or discounts on HECO and its subsidiaries’ long-term debt retired prior to maturity are classified as regulatory assets or liabilities and are amortized on a straight-line basis over the remaining original term of the retired debt. The method and periods for amortizing financing costs, premiums and discounts, including the treatment of these items when long-term debt is retired prior to maturity, have been established by the PUC as part of the rate-making process.

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.

Federal and state investment tax credits are deferred and amortized over the estimated useful lives of the properties which qualified for the credits.

Governmental tax authorities could challenge a tax return position taken by management. If the Company’s position does not prevail, the Company’s results of operations and financial condition may be adversely affected as the related deferred or current income tax asset would be impaired and written down or written off.

Earnings per share. Basic earnings per share (EPS) is computed by dividing net income by the weighted-average number of common shares outstanding for the period. Diluted EPS is computed similarly, except that common shares for dilutive stock options and dividend equivalents are added to the denominator.

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At December 31, 2002, all options to purchase common stock were included in the computation of diluted EPS. At December 31, 2001 and 2000, options to purchase 204,000 and 599,625 shares of common stock, respectively, were not included in the computation of diluted EPS because the options’ exercise prices were greater than the average market price of HEI’s common stock for 2001 and 2000, respectively, and the options were thus not dilutive.

Stock compensation. Under the 1987 Stock Option and Incentive Plan, as amended, HEI may issue an aggregate of 2,650,000 shares of common stock (1,230,190 shares unissued as of December 31, 2002) to officers and key employees as incentive stock options, nonqualified stock options, restricted stock, stock appreciation rights, stock payments or dividend equivalents. HEI has granted only nonqualified stock options and 9,000 shares of restricted stock to date. The restricted stock generally becomes unrestricted five years after the date of grant and restricted stock compensation expense has been recognized in accordance with the fair value based method of accounting in the amounts of $58,000 in 2002 and $8,000 in each of 2001 and 2000.

For the nonqualified stock options, the exercise price of each option generally equals the market price of HEI’s stock on or near the date of grant. Options generally become exercisable in installments of 25% each year for four years, and expire if not exercised ten years from the date of the grant. In general, options include dividend equivalents over the four-year vesting period and were accounted for as compensatory options under variable plan accounting in 2001 and 2000. In 2001 and 2000, the Company applied the intrinsic value-based method of accounting prescribed by Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations including Financial Accounting Standards Board (FASB) Interpretation No. 44, “Accounting for Certain Transactions involving Stock Compensation an interpretation of APB Opinion No. 25” issued in March 2000, to account for its stock options. The Company recorded stock option compensation expense of $2.6 million in 2001 and $1.9 million in 2000. For 2002, the Company applied the fair value based method of accounting prescribed by SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended, to account for its stock options. The Company recorded stock option compensation expense of $1.5 million in 2002.

In December 2002, the Company elected to adopt the recognition provisions of SFAS No. 123 as of January 1, 2002 using the “modified prospective method,” which allows recognition of stock-based employee compensation cost from the beginning of the fiscal year in which the recognition provisions are first applied as if the fair value based accounting method had been used to account for all employee awards granted, modified or settled in years since 1995.

If the accounting provisions of SFAS No. 123 had been applied to 2001 and 2000, the proforma net income and basic and diluted earnings per share would have been:

Years ended December 31	2002			2001			2000
(in thousands, except per share amounts)
Net income, as reported	$	118,217		$	83,705		$	45,744
Add: Stock option expense included in reported net income, net of tax benefits		888			1,612			1,160
Deduct: Total stock option expense determined under the fair value based method, net of tax benefits		(888	)		(788	)		(747	)
Pro forma net income	$	118,217		$	84,529		$	46,157
Earnings per share
Basic – as reported	$	3.26		$	2.48		$	1.41
Basic – pro forma	$	3.26		$	2.50		$	1.42
Diluted – as reported	$	3.24		$	2.47		$	1.40
Diluted – pro forma	$	3.24		$	2.49		$	1.41

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Information about HEI’s stock option plan is summarized as follows:

	2002				2001				2000
	Shares		(1)		Shares		(1)		Shares		(1)
Outstanding, January 1	814,250		$	35.58	813,625		$	35.22	739,875		$	36.21
Granted	147,000			43.36	170,000			36.29	154,000			30.10
Exercised	(328,225	)		37.07	(162,500	)		34.40	(47,500	)		34.28
Forfeited or expired	–			–	(6,875	)		37.85	(32,750	)		34.94
Outstanding, December 31	633,025		$	36.62	814,250		$	35.58	813,625		$	35.22
Options exercisable, December 31	272,775		$	34.93	447,250		$	36.24	452,125		$	36.24

(1) Weighted-average exercise price

The weighted-average fair value of each option granted during the year was $9.82, $7.92 and $9.83 (at grant date) in 2002, 2001 and 2000, respectively. The weighted-average assumptions used to estimate fair value include: risk-free interest rate of 4.6%, 4.8% and 6.3%; expected volatility of 17.5%, 18.9% and 16.5%; expected dividend yield of 7.0%, 7.0% and 6.8% for 2002, 2001 and 2000, respectively, and expected life of 4.5 years for each of the three years.

The weighted-average fair value of each option grant is estimated on the date of grant using a Binomial Option Pricing Model. At December 31, 2002, unexercised stock options have exercise prices ranging from $29.48 to $43.36 per common share, and a weighted-average remaining contractual life of 7.6 years.

Impairment of long-lived assets and long-lived asset to be disposed of. The Company reviews long-lived assets and certain identifiable intangibles for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell.

Recent accounting pronouncements and interpretations

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

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

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May 15, 2002. All other provisions of SFAS No. 145 are effective for financial statements issued on or after May 15, 2002. Early application of the provisions of SFAS No. 145 was encouraged. The Company adopted the provisions of SFAS No. 145 in the second quarter of 2002 with no effect on the Company’s financial statements.

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

Guarantor’s accounting and disclosure requirements for guarantees. In November 2002, the FASB issued Interpretation (FIN) No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” which elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements for periods ending after December 15, 2002 about its obligations under guarantees it has issued. FIN No. 45 also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken. The Company adopted the provisions of FIN No. 45 on January 1, 2003. Since the initial recognition and measurement provisions of FIN No. 45 are applied prospectively to guarantees issued or modified after December 31, 2002, the adoption of these provisions of FIN No. 45 had no effect on the Company’s historical financial statements.

Consolidation of variable interest entities. In January 2003, the FASB issued FIN No. 46, “Consolidation of Variable Interest Entities,” which addresses the consolidation of variable interest entities (VIEs) as defined. FIN No. 46 applies immediately to variable interests in VIEs created after January 31, 2003, and to variable interests in VIEs obtained after January 31, 2003. For a variable interest in a VIE created before February 1, 2003, FIN No. 46 is applied to the enterprise no later than the beginning of the first interim or annual reporting period beginning after June 15, 2003. The application of FIN No. 46 is not expected to have a material effect on the Company’s financial statements. FIN No. 46 requires certain disclosures in financial statements issued after January 31, 2003 if it is reasonably possible that the Company will consolidate or disclose information about VIEs when FIN No. 46 becomes effective. Such disclosures are included in Note 4.

Other. For discussions of other recent accounting pronouncements, see “Stock compensation” above and “Goodwill and other intangibles” under “Bank” below.

Reclassifications. Certain reclassifications have been made to prior years’ financial statements to conform to the 2002 presentation.

Electric utility

Regulation by the PUC. The electric utility subsidiaries are regulated by the PUC and account for the effects of regulation under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” As a result, the actions of regulators can affect the timing of recognition of revenues, expenses, assets and liabilities. Management believes HECO and its subsidiaries’ operations currently satisfy the SFAS No. 71 criteria. However, if events or circumstances should change so that those criteria are no longer satisfied, management believes that a material adverse effect on the Company’s financial statements may result as regulatory assets would be charged to expense.

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Accounts receivable. Accounts receivable are recorded at the invoiced amount. The electric utility subsidiaries assess a late payment charge on balances unpaid from the previous month. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts receivable. The Company adjusts its allowance on a monthly basis, based on its historical write-off experience. Account balances are charged off against the allowance after collection efforts have been exhausted and the potential for recovery is considered remote.

Contributions in aid of construction. The electric utility subsidiaries receive contributions from customers for special construction requirements. As directed by the PUC, the subsidiaries amortize contributions on a straight-line basis over 30 years as an offset against depreciation expense.

Electric utility revenues. Electric utility 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. Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers for billing purposes is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on the following month meter readings, monthly generation volumes, estimated customer usage by account, line losses and applicable customer rates based on historical values and current rate schedules. At December 31, 2002, customer accounts receivable include unbilled energy revenues of $60 million on a base of annual revenue of $1.3 billion. Revenue amounts recorded pursuant to a PUC interim order are subject to refund, with interest, pending a final order.

The rate schedules of the electric utility subsidiaries 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.

HECO and its subsidiaries’ operating revenues include amounts for various revenue taxes they collect from customers and pay to taxing authorities. Revenue taxes to be paid to the taxing authorities are recorded as an expense and a corresponding liability in the year the related revenues are recognized. Payments to the taxing authorities are made in the subsequent year. For 2002, HECO and its subsidiaries included $111 million of revenue taxes in “operating revenues” and $113 million (including a $2 million nonrecurring PUC fee adjustment) of revenue taxes in “taxes, other than income taxes” expense. For 2001 and 2000, HECO and its subsidiaries included $114 million and $112 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

Allowance for funds used during construction (AFUDC). AFUDC is an accounting practice whereby the costs of debt and equity funds used to finance plant construction are credited on the statement of income and charged to construction in progress on the balance sheet.

The weighted-average AFUDC rate was 8.7% in 2002 and 2001 and 8.6% in 2000, and reflected quarterly compounding.

Bank

Loans receivable. American Savings Bank, F.S.B. and subsidiaries (ASB) state loans receivable at cost less an allowance for loan losses, loan origination and commitment fees and purchase premiums and discounts. Interest on loans is credited to income as it is earned. Premiums are amortized and discounts are accreted over the estimated life of the loan using the level-yield method.

Allowance for loan losses. ASB maintains an allowance for loan losses that it believes is adequate to absorb estimated losses on all loans. The level of allowance for loan losses is based on a continuing assessment of existing risks in the loan portfolio, historical loss experience, changes in collateral values, and current and anticipated economic conditions. For business and commercial real estate loans, a risk rating system is used. Loans are rated based on the degree of risk at origination and periodically thereafter, as appropriate. A credit review department performs an evaluation of these loan portfolios to ensure compliance with the internal risk rating system and timeliness of rating changes. Adverse changes in any of the risk factors could result in higher charge-offs and loan loss provisions. When loans are deemed impaired, the amount of impairment is measured based on

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the present value of expected future cash flows discounted at the loan’s effective interest rate and the fair value of the collateral securing the loan. ASB generally ceases the accrual of interest on loans when they become 90 days past due or when there is reasonable doubt as to collectibility. ASB uses either the cash or cost recovery method to record cash receipts on impaired loans that are not accruing interest. Impairment losses are charged to the provision for loan losses and included in the allowance for loan losses. For the remaining loans receivable portfolio, allowance for loan loss allocations are determined based on a loss migration analysis. The loss migration analysis determines potential loss factors based on historical loss experience for homogeneous loan portfolios.

Real estate acquired in settlement of loans. ASB records real estate acquired in settlement of loans at the lower of cost or fair value less estimated selling expenses.

Loan origination and commitment fees. ASB defers loan origination fees (net of direct costs) and recognizes such fees as an adjustment of yield over the life of the loan. ASB also defers nonrefundable commitment fees (net of direct loan origination costs, if applicable) for commitments to originate or purchase loans and, if the commitment is exercised, recognizes such fees as an adjustment of yield over the life of the loan. If the commitment expires unexercised, ASB recognizes nonrefundable commitment fees as income upon expiration.

Goodwill and other intangibles. The Company adopted the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets” on January 1, 2002. SFAS No. 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead be tested for impairment at least annually. SFAS No. 142 also requires that intangible assets with definite useful lives be amortized over their respective estimated useful lives to their estimated residual values, and be reviewed for impairment in accordance with SFAS No. 144.

Goodwill. ASB’s $83.1 million of goodwill, which is the Company’s only intangible asset with an indefinite useful life, was tested for impairment as of January 1, 2002 and will be tested for impairment annually in the fourth quarter using data as of September 30. As of January 1, 2002 and September 30, 2002, there was no impairment of goodwill. The fair value of ASB was estimated using a valuation method based on a market approach which takes into consideration market values of comparable publicly traded companies and recent transactions of companies in the industry.

In 2001 and 2000, ASB amortized goodwill on a straight-line basis over 25 years. Management evaluated whether later events or changes in circumstances indicated the remaining estimated useful life of goodwill warranted revision or that the remaining balance of goodwill was not recoverable.

Application of the provisions of SFAS No. 142 has affected the comparability of current period results of operations with prior periods because goodwill is no longer being amortized over a 25-year period. Thus, the following “transitional” disclosures present net income and earnings per common share adjusted to eliminate goodwill amortization in 2001 and 2000 as shown below.

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Years ended December 31	2002		2001		2000
(in thousands, except per share amounts)
Consolidated
Reported net income	$	118,217	$	83,705	$	45,744
Goodwill amortization, net of tax benefits		–		3,845		3,816
Adjusted net income	$	118,217	$	87,550	$	49,560
Per common share:
Reported basic earnings	$	3.26	$	2.48	$	1.41
Goodwill amortization, net of tax benefits		–		0.11		0.12
Adjusted basic earnings	$	3.26	$	2.59	$	1.53
Per common share:
Reported diluted earnings	$	3.24	$	2.47	$	1.40
Goodwill amortization, net of tax benefits		–		0.11		0.12
Adjusted diluted earnings	$	3.24	$	2.58	$	1.52
Bank
Reported net income	$	56,225	$	48,531	$	40,630
Goodwill amortization, net of tax benefits		–		3,845		3,816
Adjusted net income	$	56,225	$	52,376	$	44,446

Amortized intangible assets.

December 31	2002				2001
(in thousands)	Gross carrying Amount		Accumulated amortization		Gross carrying amount		Accumulated amortization
Core deposit intangibles	$	20,276	$	11,741	$	20,276	$	10,010
Mortgage servicing rights		9,506		4,239		11,025		2,544
	$	29,782	$	15,980	$	31,301	$	12,554

Years ended December 31	2002		2001		2000
(in thousands)
Aggregate amortization expense	$	3,426	$	2,981	$	2,575

The estimated aggregate amortization expense for ASB’s core deposits and mortgage servicing rights for 2003, 2004, 2005, 2006 and 2007 is $4.3 million, $3.5 million, $3.0 million, $2.6 million and $2.3 million, respectively.

Core deposit intangibles are amortized each year at the greater of the actual attrition rate of such deposit base or 10% of the original value. Core deposit intangibles are reviewed for impairment based on their estimated fair value.

ASB capitalizes mortgage servicing rights acquired through either the purchase or origination of mortgage loans for sale or securitization with servicing rights retained. Changes in mortgage interest rates impact the value of ASB’s mortgage servicing rights. Rising interest rates typically result in slower prepayment speeds in the loans being serviced for others which increases the value of mortgage servicing rights, whereas declining interest rates typically result in faster prepayment speeds which decreases the value of mortgage servicing rights and increases the amortization of the mortgage servicing rights. Currently, ASB does not hedge its mortgage servicing rights against this risk. During 2002, mortgage servicing rights acquired were not significant.

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2 • Segment financial information

The electric utility and bank segments are strategic business units of the Company that offer different products and services and operate in different regulatory environments. The accounting policies of the segments are the same as those described in the summary of significant accounting policies, except that income taxes for each segment are calculated on a “stand-alone” basis. HEI evaluates segment performance based on income from continuing operations. The Company accounts for intersegment sales and transfers as if the sales and transfers were to third parties, that is, at current market prices. Intersegment revenues consist primarily of interest and preferred dividends.

Electric utility

HECO and its wholly-owned operating subsidiaries, Hawaii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (MECO), are electric public utilities in the business of generating, purchasing, transmitting, distributing and selling electric energy, and are regulated by the PUC.

Bank

ASB is a federally chartered savings bank providing a full range of banking services to individual and business customers through its branch system in Hawaii. ASB is subject to examination and comprehensive regulation by the Department of Treasury, Office of Thrift Supervision (OTS) and the Federal Deposit Insurance Corporation (FDIC), and is subject to reserve requirements established by the Board of Governors of the Federal Reserve System. By reason of the regulation of its subsidiary, ASB Realty Corporation, ASB is also subject to regulation by the Hawaii Commissioner of Financial Institutions.

Other

“Other” includes amounts for the holding companies and other subsidiaries not qualifying as reportable segments.

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(in thousands)	Electric Utility		Bank		Other			Total
2002
Revenues from external customers	$	1,257,171	$	399,255	$	(2,725	)	$	1,653,701
Intersegment revenues (eliminations)		5		—		(5	)		—
Revenues		1,257,176		399,255		(2,730	)		1,653,701
Depreciation and amortization		116,800		22,784		1,409			140,993
Interest expense		44,232		152,882		28,060			225,174
Profit (loss)*		146,863		87,299		(52,253	)		181,909
Income taxes (benefit)		56,658		31,074		(24,040	)		63,692
Income (loss) from continuing operations		90,205		56,225		(28,213	)		118,217
Capital expenditures		114,558		13,117		407			128,082
Assets (at December 31, 2002, including net assets of discontinued operations)		2,436,386		6,328,606		111,511			8,876,503
2001
Revenues from external customers	$	1,289,297	$	444,602	$	(6,622	)	$	1,727,277
Intersegment revenues (eliminations)		7		—		(7	)		—
Revenues		1,289,304		444,602		(6,629	)		1,727,277
Depreciation and amortization		113,455		14,444		1,645			129,544
Interest expense		47,056		213,585		31,670			292,311
Profit (loss)*		143,716		76,475		(54,288	)		165,903
Income taxes (benefit)		55,416		27,944		(25,203	)		58,157
Income (loss) from continuing operations		88,300		48,531		(29,085	)		107,746
Capital expenditures		115,540		9,827		941			126,308
Assets (at December 31, 2001, including net assets of discontinued operations)		2,389,738		6,011,448		116,757			8,517,943
2000
Revenues from external customers	$	1,277,140	$	450,878	$	4,293		$	1,732,311
Intersegment revenues (eliminations)		30		4		(34	)		—
Revenues		1,277,170		450,882		4,259			1,732,311
Depreciation and amortization		107,325		9,690		1,807			118,822
Interest expense		49,062		238,875		28,236			316,173
Profit (loss)*		142,661		64,404		(36,570	)		170,495
Income taxes (benefit)		55,375		23,774		(17,990	)		61,159
Income (loss) from continuing operations		87,286		40,630		(18,580	)		109,336
Capital expenditures		130,089		3,839		648			134,576
Assets (at December 31, 2000, including net assets of discontinued operations)		2,392,858		5,969,315		156,521			8,518,694

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

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

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3 • Electric utility subsidiary

Selected consolidated financial information

Hawaiian Electric Company, Inc. and subsidiaries

Income statement data
Years ended December 31	2002			2001			2000
(in thousands)
Revenues
Operating revenues	$	1,252,929		$	1,284,312		$	1,270,635
Other-nonregulated		4,247			4,992			6,535
		1,257,176			1,289,304			1,277,170
Expenses
Fuel oil		310,595			346,728			362,905
Purchased power		326,455			337,844			311,207
Other operation		131,910			125,565			123,779
Maintenance		66,541			61,801			66,069
Depreciation		105,424			100,714			98,517
Taxes, other than income taxes		120,118			120,894			119,784
Other-nonregulated		1,177			1,813			1,818
		1,062,220			1,095,359			1,084,079
Operating income from regulated and nonregulated activities		194,956			193,945			193,091
Allowance for equity funds used during construction		3,954			4,239			5,380
Interest and other charges		(52,822	)		(55,646	)		(57,652	)
Allowance for borrowed funds used during construction		1,855			2,258			2,922
Income before income taxes and preferred stock dividends of HECO		147,943			144,796			143,741
Income taxes		56,658			55,416			55,375
Income before preferred stock dividends of HECO		91,285			89,380			88,366
Preferred stock dividends of HECO		1,080			1,080			1,080
Net income for common stock	$	90,205		$	88,300		$	87,286

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Balance sheet data
December 31	2002			2001
(in thousands)
Assets
Utility plant, at cost
Property, plant and equipment	$	3,217,016		$	3,100,297
Less accumulated depreciation		(1,367,954	)		(1,266,332	)
Construction in progress		164,300			170,558
Net utility plant		2,013,362			2,004,523
Regulatory assets		105,568			111,376
Other		317,456			273,839
	$	2,436,386		$	2,389,738
Capitalization and liabilities
Common stock equity	$	923,256		$	877,154
Cumulative preferred stock- not subject to mandatory redemption (dividend rates of 4.25-7.625%)		34,293			34,293
HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO and HECO-guaranteed debentures (distribution rates of 7.30% and 8.05%)		100,000			100,000
Long-term debt		705,270			685,269
Total capitalization		1,762,819			1,696,716
Short-term borrowings from affiliate		5,600			48,297
Deferred income taxes		158,367			145,608
Contributions in aid of construction		218,094			213,557
Other		291,506			285,560
	$	2,436,386		$	2,389,738

Regulatory assets. In accordance with SFAS No. 71, HECO and its subsidiaries’ financial statements reflect assets and costs based on current cost-based rate-making regulations. Continued accounting under SFAS No. 71 requires that certain criteria be met. Management believes HECO and its subsidiaries’ operations currently satisfy the criteria. However, if events or circumstances change so that the criteria are no longer satisfied, management believes that a material adverse effect on the Company’s financial statements may result as the regulatory assets would be charged to expense.

Regulatory assets are expected to be fully recovered through rates over PUC authorized periods ranging from one to 36 years (period noted in parenthesis) and include the following deferred costs:

December 31	2002		2001
(in thousands)
Income taxes (1 to 36 years)	$	64,278	$	62,467
Postretirement benefits other than pensions (10 years)		17,897		19,687
Unamortized expense and premiums on retired debt and equity issuances (2 to 26 years)		11,005		12,100
Integrated resource planning costs (1 year)		1,965		6,243
Vacation earned, but not yet taken (1 year)		4,776		4,929
Other (1 to 4 years)		5,647		5,950
	$	105,568	$	111,376

Cumulative preferred stock. Certain cumulative preferred stock of HECO and its subsidiaries is redeemable at the option of the respective company at a premium or par, but none is subject to mandatory redemption.

Major customers. HECO and its subsidiaries received approximately 9% ($119 million), 10% ($127 million) and 10% ($123 million) of their operating revenues from the sale of electricity to various federal government agencies in 2002, 2001 and 2000, respectively.

Commitments and contingencies

Fuel contracts. HECO and its subsidiaries have contractual agreements to purchase minimum quantities of fuel oil and diesel fuel through 2004 (at prices tied to the market prices of petroleum products in Singapore and Los Angeles). Based on the average price per barrel at January 1, 2003, the estimated cost of minimum purchases under the fuel supply contracts for 2003 is $329 million. The actual cost of purchases in 2003 could vary

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substantially from this estimate as a result of changes in market prices, quantities actually purchased and/or other factors. HECO and its subsidiaries purchased $317 million, $328 million and $359 million of fuel under contractual agreements in 2002, 2001 and 2000, respectively.

Power purchase agreements. At December 31, 2002, HECO and its subsidiaries had power purchase agreements for 534 megawatts (MW) of firm capacity. The PUC allows rate recovery for energy and firm capacity payments under these agreements. Assuming that each of the agreements remains in place for its current term and the minimum availability criteria in the power purchase agreements are met, aggregate minimum fixed capacity charges are expected to be approximately $123 million each in 2003 and 2004, $118 million each in 2005, 2006 and 2007 and a total of $1.6 billion in the period from 2008 through 2030.

In general, HECO and its subsidiaries base their payments under the power purchase agreements upon available capacity and energy and they are generally not required to make payments for capacity if the contracted capacity is not available, and payments are reduced, under certain conditions, if available capacity drops below contracted levels. In general, the payment rates for capacity have been predetermined for the terms of the agreements. Energy payments will vary over the terms of the agreements. HECO and its subsidiaries pass on changes in the fuel component of the energy charges to customers through the energy cost adjustment clause in their rate schedules. HECO and its subsidiaries do not operate nor participate in the operation of any of the facilities that provide power under the agreements. Title to the facilities does not pass to HECO or its subsidiaries upon expiration of the agreements, and the agreements do not contain bargain purchase options for the facilities.

Interim increases. At December 31, 2002, HECO and its subsidiaries had recognized $16 million of revenues with respect to interim orders regarding certain integrated resource planning costs, which revenues are subject to refund, with interest, if and to the extent they exceed the amounts allowed in final orders.

HELCO power situation. In 1991, HELCO began planning to meet increased electric generation demand forecasted for 1994. HELCO’s plans were to install at its Keahole power plant two 20 MW combustion turbines (CT-4 and CT-5), followed by an 18 MW heat steam recovery generator (ST-7), at which time these units would be converted to a 56 MW (net) dual-train combined-cycle unit. In January 1994, the PUC approved expenditures for CT-4, which HELCO had planned to install in late 1994. In 1995, the PUC allowed HELCO to pursue construction of and commit expenditures for CT-5 and ST-7, but noted that such costs are not to be included in rate base until the project is installed and “is used and useful for utility purposes.” The PUC at that time also ordered HELCO to continue negotiating with independent power producers (IPPs), stating that the facility to be built should be the one that can be most expeditiously put into service at “allowable cost.”

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

As a result of a September 19, 2002 decision by the Third Circuit Court of the State of Hawaii (Circuit Court), relating to an extension of a construction deadline and described below under “Land use permit amendment,” the construction of CT-4 and CT-5, which had commenced in April 2002 after HELCO had obtained a final air permit and the Circuit Court had lifted a stay on construction, has been suspended. HELCO has appealed this ruling to the Hawaii Supreme Court and is considering other options that may allow HELCO to complete the installation of CT-4 and CT-5 (including seeking a land use reclassification of the Keahole site from the State Land Use Commission). If none of these options is ultimately successful, or if other permitting issues or problems arise which HELCO cannot satisfactorily resolve, HELCO may be unable to complete the installation of CT-4 and CT-5.

The following is a detailed discussion of the existing Keahole situation, including a description of its potential financial statement implications under “Management’s evaluation; costs incurred.”

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Land use permit amendment. The Circuit Court ruled in 1997 that because the BLNR had failed to render a valid decision on HELCO’s application to amend its land use permit before the statutory deadline in April 1996, HELCO was entitled to use its Keahole site for the expansion project (HELCO’s “default entitlement”). Final judgments of the Circuit Court related to this ruling are on appeal to the Hawaii Supreme Court, which in 1998 denied motions to stay the Circuit Court’s final judgment pending resolution of the appeal.

The Circuit Court’s final judgment provided that HELCO must comply with the conditions in its application and with the standard land use conditions insofar as those conditions were not inconsistent with HELCO’s default entitlement. There have been numerous proceedings before the Circuit Court and the BLNR in which certain parties (a) have sought determinations of what conditions apply to HELCO’s default entitlement, (b) have claimed that HELCO has not complied with applicable land use conditions and that its default entitlement should thus be forfeited, (c) have claimed that HELCO will not be able to operate the proposed plant without violating applicable land use conditions and provisions of Hawaii’s Air Pollution Control Act and Noise Pollution Act and (d) have sought orders enjoining any further construction at the Keahole site.

Although there has not been a final resolution of these claims, there have been several significant rulings relating to these claims, some of which may adversely affect HELCO’s ability to construct and efficiently operate CT-4 and CT-5. First, based on a change by the DOH in its interpretation of the noise rules it promulgated under the Hawaii Noise Pollution Act, the Circuit Court ruled that a stricter noise standard than the previously applied standard applies to HELCO’s plant, but left enforcement of the ruling to the DOH. HELCO filed a separate complaint for declaratory relief against the DOH seeking the invalidation of the noise rules on constitutional and other grounds. The Circuit Court denied HELCO’s motion for summary judgment, finding that the noise rules are constitutional on their face but specifically not ruling on the constitutionality of the rules as applied to Keahole. HELCO appealed the final judgment to the Hawaii Supreme Court in August 1999 and a decision on that appeal is pending. The DOH has been periodically monitoring noise levels at the site. If the DOH were to issue a notice of violation based on the stricter standards, HELCO may, among other things, assert that the noise regulations, as applied to it at Keahole, are unconstitutional. Meanwhile, while not waiving possible claims or defenses that it might have against the DOH, HELCO has installed noise mitigation measures on the existing units at Keahole and, should construction be allowed to continue, is planning to implement additional noise mitigation measures for both the existing units and for CT-4 and CT-5. The estimated cost for these additional noise mitigation measures (for the existing units and CT-4 and CT-5) is $5 million, which would be capitalized. While the noise mitigation measures were being implemented, HELCO applied to the DOH and received approval for a noise permit through 2003, which has since been extended to July 2007.

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

55

provided.” In April 2002, based on this BLNR decision, the Circuit Court lifted the stay on construction in light of the BLNR’s Order, and construction activities on CT-4 and CT-5 then commenced.

Keahole Defense Coalition, Inc. (KDC) and two individuals appealed the BLNR’s March 25, 2002 Order to the Circuit Court, as did the Department of Hawaiian Home Lands. On September 19, 2002, the Circuit Court issued a letter to the parties indicating the Circuit Court’s decision to reverse the BLNR’s Order. The letter states that:

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

2. The conclusions of law are erroneous.

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

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

The Circuit Court issued an Order to this effect on October 3, 2002.

On November 1, 2002, HELCO filed a notice of appeal of the October 3, 2002 Order (which appeal will be decided by the Hawaii Supreme Court or Hawaii Intermediate Court of Appeals). On November 15, 2002, HELCO also filed with the Hawaii Supreme Court a Motion for Stay Pending Disposition of Appeal and a Motion to Expedite Transmission of Record on Appeal. The Motion to Expedite was denied on December 10, 2002. The Motion for Stay was denied in early 2003. On November 25, 2002, KDC and two individuals filed with the Supreme Court a Motion to Dismiss this appeal on the basis that the case was moot since HELCO no longer had a default entitlement because it allegedly violated the BLNR’s March 25, 2002 Order by withdrawing its application to the LUC for a boundary amendment. That motion was denied in early 2003. Accordingly, the Hawaii Supreme Court continues to assert jurisdiction over this appeal and briefs will be filed.

On November 1, 2002, HELCO filed with the Circuit Court a notice of appeal of the original November 9, 2000 ruling that the three-year deadline had expired in April 1999. In early 2003, the Supreme Court dismissed that appeal for lack of jurisdiction. The Supreme Court’s Order stated that HELCO’s appeal was not timely filed because it was not filed within 30 days of the Circuit Court’s November 9, 2000 Order, even though the Circuit Court ruled at the time that its Order could not yet be appealed.

In the meantime, construction activities on CT-4 and CT-5 have been suspended and steps have been taken to secure the site and protect equipment and personnel.

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

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

Land Use Commission petition. One of the conditions of the construction period extension granted by the BLNR (which the Circuit Court’s October 3, 2002 Order now has reversed) was that HELCO file an application for a boundary amendment with the LUC to remove the site from the conservation district. HELCO filed the application on June 21, 2002. A hearing before the LUC was held on September 12, 2002, at which public testimony was taken

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and memoranda were received regarding the jurisdiction of the LUC in dealing with the HELCO petition. In light of subsequent events, HELCO withdrew its petition on October 3, 2002. Under LUC rules, after such a voluntary withdrawal the applicant may submit another petition for the same property one year from the date of withdrawal. HELCO intends to submit a new petition for reclassification in the fourth quarter of 2003.

IPP Complaints. Three IPPs—Kawaihae Cogeneration Partners (KCP), Enserch Development Corporation (Enserch) and Hilo Coast Power Company (HCPC)—filed separate complaints with the PUC in 1993, 1994 and 1999, respectively, alleging that they are each entitled to a power purchase agreement (PPA) to provide HELCO with additional capacity. KCP and Enserch each claimed they would be a substitute for HELCO’s planned expansion of Keahole.

The Enserch and HCPC complaints have been resolved by HELCO’s entry into two PPAs, which were necessary to ensure reliable service to customers on the island of Hawaii, but, in the opinion of management, do not supplant the need for CT-4 and CT-5. HELCO can terminate the PPA with HCPC prior to its 2004 expiration date, for a fee.

In October 1999, the Circuit Court ruled that the lease for KCP’s proposed plant site was invalid. In January 2003, the PUC issued an order denying KCP’s July 1999 request to reopen KCP’s 1993 complaint docket and to enforce the Public Utility Regulatory Policies Act of 1978. Based on these rulings and for other reasons, management believes that KCP’s proposal for a PPA is not viable and, therefore, will not impact the need for CT-4 and CT-5.

Management’s evaluation; costs incurred. In addition to the appeal of the October 3, 2002 Circuit Court’s Order filed on November 1, 2002, HELCO is considering other options that may allow HELCO to complete the installation of CT-4 and CT-5, including seeking a land use reclassification of the Keahole site from the State Land Use Commission. At this time, the likelihood of success of any of these options cannot be ascertained. Even if the Circuit Court’s Order is ultimately overturned on appeal, however, construction is likely to be further significantly delayed, and the costs to complete construction may be significantly increased, due to the time that is likely to be required to resolve the legal proceedings. In the meantime, one concern of HELCO’s management is the condition and performance of certain aging generators on the HELCO system, which were intended to be retired or to be operated less frequently once CT-4 and CT-5 were installed, as well as the current operating status of various IPPs, which provide approximately 43% of HELCO’s generating capacity. Another concern is the possibility of power interruptions under exigent circumstances, including rolling blackouts, as IPPs and/or HELCO’s generating units become unavailable or less available (i.e., available at lower capacity) due to forced outages or planned maintenance. Such incidents occurred or were at risk of occurring on October 3, 2002 and November 8, 2002. As it has done on such occasions in the past, HELCO will endeavor to avert power interruptions, including rolling blackouts, in the future through a number of actions in addition to managing the generating units on its system, such as requesting customers to reduce demand during critical periods such as the peak evening hours. Under current system conditions, however, there can be no assurance that power interruptions will not occur.

The recovery of costs relating to CT-4 and CT-5 are subject to the rate-making process governed by the PUC. Management believes no adjustment to costs incurred to put CT-4 and CT-5 into service is required as of December 31, 2002. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HELCO may be required to write off a material portion of the costs incurred in its efforts to put these units into service whether or not CT-4 and CT-5 are installed. As of December 31, 2002, HELCO’s costs incurred in its efforts to put CT-4 and CT-5 into service and to support existing units (excluding costs the PUC permitted to be transferred to plant-in-service for pre-air permit facilities) amounted to approximately $82 million, including $32 million for equipment and material purchases, $30 million for planning, engineering, permitting, site development and other costs and $20 million for AFUDC. In addition to the $82 million in construction in progress, construction and/or purchase commitments related to CT-4 and CT-5 outstanding as of December 31, 2002 are estimated at approximately $0.6 million.

Although management believes it has acted prudently with respect to the Keahole project, effective December 1, 1998, HELCO discontinued the accrual of AFUDC on CT-4 and CT–5 due in part to the delays through that date and the potential for further delays. HELCO has also deferred plans for ST-7 to a date outside the near-term planning horizon. No costs for ST-7 are included in construction in progress.

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

Construction of the Kamoku to Pukele transmission line in its 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 have opposed the project, particularly the overhead portion of the line.

In November 2000, the DLNR accepted a Revised Final Environmental Impact Statement (RFEIS) prepared in support of HECO’s application for a CDUP. In January 2001, three organizations and an individual filed a complaint against the DLNR and HECO challenging the DLNR’s acceptance of the RFEIS and seeking, among other things, a judicial declaration that the RFEIS is inadequate and null and void. HECO continues to contest the lawsuit.

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

HECO continues to believe that the proposed project is needed. The project would address future potential transmission line overloads in the Northern and Southern corridors under certain contingencies (in which one of the three lines feeding power to the Koolau/Pukele area served by the Northern Corridor, or to the downtown Honolulu area served by the Southern Corridor, is out for maintenance, and a second line incurs an unexpected outage), and improves the reliability of the Pukele substation. The line overload contingencies could occur, given current load growth forecasts, in 2005 for the Northern Corridor, but not until 2013 or later in the Southern Corridor. The Pukele substation, at the end of the Northern corridor, serves approximately 18% of Oahu’s electrical load, including Waikiki. If one of the 138 kV transmission lines to the Pukele substation fails while the other is out for maintenance, a major system outage would result.

HECO is evaluating alternative ways to accomplish the project, and possible future actions to expedite PUC review of the alternatives (and the need for the project). Until this evaluation of alternatives is completed, an estimated project completion date cannot be determined.

As of December 31, 2002, the accumulated costs related to the Kamoku to Pukele transmission line amounted to $17 million, including $12 million for planning, engineering and permitting costs and $5 million for AFUDC. These costs are recorded in construction in progress. The recovery of costs relating to the Kamoku to Pukele transmission line is subject to the rate-making process administered by the PUC. Management believes no adjustment to project costs incurred is required as of December 31, 2002. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HECO may be required to write off a material portion or all of the project costs incurred in its efforts to put the Kamoku to Pukele transmission line into service whether or not the project is completed.

State of Hawaii, ex rel., Bruce R. Knapp, Qui Tam Plaintiff, and Beverly Perry, on behalf of herself and all others similarly situated, Class Plaintiff, vs. The AES Corporation, AES Hawaii, Inc., HECO, and HEI. On April 22 and 23, 2002, HECO and HEI, respectively, were served with a complaint filed in the Circuit Court for the First Circuit of Hawaii which alleges that the State of Hawaii and HECO’s other customers have been overcharged for electricity as a result of alleged excessive prices in the amended power purchase agreement (Amended PPA) between defendants HECO and AES Hawaii, Inc. (AES-HI). AES-HI is a subsidiary of The AES Corporation (AES), which guarantees certain obligations of AES-HI under the Amended PPA.

HECO entered into a PPA with AES Barbers Point, Inc. (now known as AES-HI) in March 1988, and the PPA was amended in August 1989. The AES-HI 180 MW coal-fired cogeneration plant, which became operational in September 1992, utilizes a “clean-coal” technology and is designed to sell sufficient steam to be a “Qualifying Facility” under the Public Utility Regulatory Policies Act of 1978. The Amended PPA, which has a 30-year term, was

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approved by the PUC in December 1989, following contested case hearings in October 1988, an initial Decision and Order in July 1989, an amendment of the PPA in August 1989, and further contested case hearings in November 1989. Intervenors included the state Consumer Advocate and the U.S. Department of Defense. The PUC proceedings addressed a number of issues, including whether the prices for capacity and energy in the Amended PPA were less than HECO’s long-term estimated avoided costs, whether HECO needed the capacity to be provided by AES-HI, and whether the terms and conditions of the Amended PPA were reasonable.

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

On May 22, 2002, AES, with the consent of HECO and HEI, removed the case to the U.S. District Court for the District of Hawaii (District Court) on the ground that the action arises under and is completely preempted by the Public Utility Regulatory Policies Act of 1978. On June 12, 2002, HECO and HEI filed a motion to dismiss the complaint on the grounds that the plaintiffs’ claims either arose prior to enactment of the Hawaii False Claims Act, which does not have retroactive application, or are barred by the applicable statute of limitations. AES also filed a motion to dismiss, on the same and additional grounds.

Plaintiffs moved to remand the case to state court on June 21, 2002. On November 14, 2002, the District Court Judge remanded the case back to state court and denied plaintiffs’ request for attorneys’ fees and costs.

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

As a result of the Circuit Court’s ruling, the only claim that appears to remain is under the Hawaii False Claims Act based on allegations that false bills or claims were submitted to the State after May 26, 2000. Under the False Claims Act, a defendant may be liable to a qui tam plaintiff for treble damages, plus civil penalties of a minimum of $5,000 for each false claim, plus attorneys’ fees and costs incurred in the action. The Plaintiffs appear to claim that each monthly bill submitted to each state agency and office on Oahu constitutes a separate false claim.

Management intends to vigorously defend the lawsuit.

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

In 1999, the Work Group submitted reports to the DOH presenting environmental conditions and recommendations for additional data gathering to allow for an assessment of the need for risk-based corrective action. The Work Group also engaged a consultant who identified 27 additional potentially responsible parties (PRPs) who were not members of the Work Group, including YB. Under the terms of the 1999 agreement for the

59

sale of YB, HEI and TOOTS (formerly HTB) have specified indemnity obligations, including obligations with respect to the Honolulu Harbor investigation.

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

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

In September 2001, the EPA and DOH concurrently issued notices of interest (collectively, the Second NOI) to the members of the Participating Parties, including HECO and TOOTS. The Second NOI identified several investigative and preliminary oil removal tasks to be taken at certain valve control facilities associated with historic pipelines in the Iwilei Unit of the Honolulu Harbor site. The Participating Parties performed the tasks identified in the Second NOI (the Phase I Pipeline Investigation) and developed a proposal for additional investigation (the Phase 2 Pipeline Investigation), which proposal the EPA and DOH approved. The Participating Parties have completed the Phase 2 Pipeline Investigation and anticipate submitting a report to the DOH and EPA in the first quarter of 2003. With the approval of the EPA and DOH, the Participating Parties also constructed a pilot Dual Phase Extraction System to remove petroleum liquids and vapors from the subsurface in a portion of the Iwilei District. Operation of the pilot extraction system began in October 2002. The pilot study supplements ongoing petroleum removal activities by the Participating Parties from wells and trenches installed as part of the investigation. The Participating Parties are currently updating the Conceptual Site Model for the Iwilei Unit, In addition, the Participating Parties plan to undertake a Feasibility Study during 2003 to identify and evaluate various remedial strategies to address petroleum products identified in the subsurface of the Iwilei District. Based on the Conceptual Site Model and the Feasibility Study, the Participating Parties will also recommend implementation of remedial strategies, where appropriate.

In October 2002, HECO and three other companies that currently have petroleum handling operations (the Operating Companies) in the Iwilei Unit entered into an agreement with the DOH to evaluate their facilities to determine whether they currently are releasing petroleum to the subsurface in the Iwilei Unit. HECO has previously investigated its facilities in the Iwilei Unit and routinely maintains them, and therefore believes that the Operating Companies evaluation will confirm that HECO’s current operations are not releasing petroleum in the Iwilei Unit.

Management has developed a preliminary estimate of costs for continuing investigative work, remedial activities and monitoring at the Iwilei Unit of the site. Management estimates that HECO will incur approximately $1.1 million (of which $0.2 million has been incurred through December 31, 2002) and TOOTS will incur approximately $0.3 million in connection with work to be performed at the site primarily from January 2002 through December 2004. These estimates were expensed in 2001. However, because (1) the full scope and extent of additional investigative work, remedial activities and monitoring are unknown at this time, (2) the final cost allocation method has not yet been determined and (3) management cannot estimate the costs to be incurred (if any) for the sites other than the Iwilei Unit (including its Honolulu power plant site), the HECO and TOOTS cost estimates may be subject to significant change and additional material investigative and remedial costs may be incurred after December 2004.

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Collective bargaining agreements. Approximately 62% of the employees of HECO, HELCO and MECO are represented by the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260 (IBEW), and are covered by collective bargaining agreements, which expire at midnight on October 31, 2003. Should the IBEW not reach agreements with HECO, HELCO and MECO upon the expiration of the existing agreements, HECO and its subsidiaries’ results of operations could be adversely affected.

4 • Bank subsidiary

Selected consolidated financial information

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

Income statement data
Years ended December 31	2002			2001			2000
(in thousands)
Interest and dividend income
Interest and fees on loans	$	203,082		$	231,858		$	254,502
Interest on mortgage-related securities		135,252			152,181			152,340
Interest and dividends on investment securities		7,896			15,612			16,733
		346,230			399,651			423,575
Interest expense
Interest on deposit liabilities		73,631			116,531			119,192
Interest on Federal Home Loan Bank advances		58,608			68,740			82,294
Interest on securities sold under repurchase agreements		20,643			28,314			37,389
		152,882			213,585			238,875
Net interest income		193,348			186,066			184,700
Provision for loan losses		9,750			12,500			13,050
Net interest income after provision for loan losses		183,598			173,566			171,650
Other income
Fees from other financial services		21,254			17,194			14,349
Fee income on deposit liabilities		15,734			9,401			8,760
Fee income on other financial products		10,063			8,451			3,212
Fee income on loans serviced for others, net		(164	)		2,458			2,764
Gain (loss) on sale of securities		(640	)		8,044			—
Writedown of investment		—			(6,164	)		(5,838	)
Other income		6,778			5,567			4,060
		53,025			44,951			27,307
General and administrative expenses
Compensation and employee benefits		59,594			51,932			48,423
Occupancy and equipment		30,086			28,638			27,333
Data processing		11,167			10,408			6,893
Consulting		7,693			3,825			5,449
Amortization of goodwill and core deposit intangibles		1,731			6,706			7,613
Other		33,469			34,909			33,205
		143,740			136,418			128,916
Income before minority interests and income taxes		92,883			82,099			70,041
Minority interests		173			213			225
Income taxes		31,074			27,944			23,774
Income before preferred stock dividends		61,636			53,942			46,042
Preferred stock dividends		5,411			5,411			5,412
Net income for common stock	$	56,225		$	48,531		$	40,630

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Balance sheet data
December 31	2002		2001
(in thousands)
Assets
Cash and equivalents	$	214,704	$	425,595
Available-for-sale mortgage-related securities		1,952,317		1,598,100
Available-for-sale mortgage-related securities pledged for repurchase agreements		784,362		756,749
Held-to-maturity investment securities		89,545		84,211
Loans receivable, net		2,993,989		2,857,622
Other		196,117		187,217
Goodwill and other intangibles		97,572		101,954
	$	6,328,606	$	6,011,448
Liabilities and equity
Deposit liabilities–noninterest bearing	$	369,961	$	246,633
Deposit liabilities–interest bearing		3,430,811		3,432,953
Securities sold under agreements to repurchase		667,247		683,180
Advances from Federal Home Loan Bank		1,176,252		1,032,752
Other		137,888		130,494
		5,782,159		5,526,012
Minority interests and preferred stock of subsidiary		3,417		3,409
Preferred stock		75,000		75,000
Common stock		243,628		242,786
Retained earnings		192,692		165,564
Accumulated other comprehensive income (loss)		31,710		(1,323	)
		468,030		407,027
	$	6,328,606	$	6,011,448

Investment and mortgage-related securities

December 31	2002									2001
(in thousands)	Amortized cost		Gross unrealized gains		Gross unrealized losses			Estimated fair value		Amortized Cost		Gross unrealized gains		Gross unrealized losses			Estimated fair value
Available-for-sale
Mortgage-related securities:
Private issue	$	876,561	$	8,373	$	(7,722	)	$	877,212	$	894,849	$	2,689	$	(17,961	)	$	879,577
FHLMC		539,041		7,784		(76	)		546,749		318,030		3,631		(207	)		321,454
GNMA		225,002		7,136		—			232,138		149,778		2,501		(160	)		152,119
FNMA		1,043,407		37,207		(34	)		1,080,580		990,049		14,959		(3,309	)		1,001,699
	$	2,684,011	$	60,500	$	(7,832	)	$	2,736,679	$	2,352,706	$	23,780	$	(21,637	)	$	2,354,849

As of December 31, 2002 and 2001, ASB’s held-to-maturity investment securities consisted of stock in FHLB of Seattle.

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December 31, 2000	Amortized cost/ carrying value		Gross unrealized gains		Gross unrealized losses			Estimated fair value
(in thousands)
Available-for-sale
Investment securities-collateralized debt obligations	$	107,955	$	—	$	—		$	107,955
Mortgage-related securities:
FHLMC		10,477		—		(23	)		10,454
FNMA		46,037		267		(45	)		46,259
		56,514		267		(68	)		56,713
	$	164,469	$	267	$	(68	)	$	164,668
Held-to-maturity
Investment securities: Stock in FHLB of Seattle	$	78,661	$	—	$	—		$	78,661
Collateralized debt obligations		13,062		—		(262	)		12,800
		91,723		—		(262	)		91,461
Mortgage-related securities:
Private issue		1,094,723		9,243		(8,917	)		1,095,049
FHLMC		133,623		1,500		(257	)		134,866
GNMA		238,331		1,034		(475	)		238,890
FNMA		547,437		3,981		(5,050	)		546,368
		2,014,114		15,758		(14,699	)		2,015,173
	$	2,105,837	$	15,758	$	(14,961	)	$	2,106,634

ASB owns private-issue mortgage-related securities and mortgage-related securities issued by the Federal Home Loan Mortgage Corporation (FHLMC), Government National Mortgage Association (GNMA) and Federal National Mortgage Association (FNMA). Contractual maturities are not presented for mortgage-related securities because these securities are not due at a single maturity date. The weighted-average interest rate for mortgage-related securities at December 31, 2002 and 2001 was 5.62% and 6.10%, respectively.

ASB pledged mortgage-related securities with a carrying value of approximately $78 million and $108 million at December 31, 2002 and 2001, respectively, as collateral to secure public funds, deposits with the Federal Reserve Bank of San Francisco and advances from the FHLB of Seattle. At December 31, 2002 and 2001, mortgage-related securities sold under agreements to repurchase had a carrying value of $784 million and $757 million, respectively.

Pursuant to SFAS No. 133, on January 1, 2001, approximately $2 billion in mortgage-related securities and $13 million in investment securities having estimated fair values of approximately $2 billion and $13 million, respectively, were reclassified from held-to-maturity to available-for-sale. ASB did not sell held-to-maturity investment and mortgage-related securities in 2002, 2001 or 2000.

Disposition of certain debt securities. In June 2000, the OTS advised ASB that four trust certificates, in the original aggregate principal amount of $114 million, were impermissible investments under regulations applicable to federal savings banks and subsequently required ASB to dispose of the securities. The original trust certificates were purchased through two brokers and represented (i) the right to receive the principal amount of the trust certificates at maturity from an Aaa-rated swap counterparty (principal swap) and (ii) the right to receive the cash flow received on subordinated notes issued by a collateralized loan obligation (income notes or equity notes). As a result, ASB recognized interest income on these securities on a cash basis and reclassified these trust certificates from held-to-maturity status to available-for-sale status in its financial statements, recognizing a $3.8 million net loss ($5.8 million pretax) on the writedown of these securities to their then-current estimated fair value. In the first six months of 2001, ASB recognized an additional $4.0 million net loss ($6.2 million pretax) on the writedown of three of these trust certificates to their then-current estimated fair value. In April 2001, ASB sold one of the trust certificates for $30 million, an amount approximating the original purchase price.

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After ASB demanded that PaineWebber Incorporated (the broker through whom the remaining three trust certificates were purchased) rescind the transactions, ASB filed a lawsuit against PaineWebber Incorporated. ASB is seeking rescission or other remedies, including recovery of any losses ASB (directly and through its indemnification of HEI) may incur as a result of its purchase and ownership of these trust certificates.

To bring ASB into compliance with the OTS direction, ASB directed the trustees to terminate the principal swap component of the three trust certificates and received $43 million from the swaps. Prior to terminating the swaps, ASB had received $2 million of cash from the three trust certificates. After terminating the swaps, the related equity notes were sold by the swap counterparty to HEI. In May 2001, HEI purchased two series of the income notes for approximately $21 million and, in July 2001, HEI purchased the third series of income notes for approximately $7 million. As of December 31, 2002, HEI had received $9.1 million of cash from these income notes. The three series of income notes purchased by HEI represent residual equity interests in three entities (Avalon CLO, Pilgrim 1999-01 CLO, and Avalon CLO II) which, as of December 31, 2002, held cash and collateralized corporate debt securities having an estimated par value of approximately $1.7 billion. The entities manage the portfolio of collateralized debt securities, pay expenses and make payments to the various class note holders as specified in the various note agreements. HEI is not the primary beneficiary of these entities, and HEI’s maximum pre-tax exposure to additional loss as a result of its ownership of the income notes is $7 million as of December 31, 2002.

Due to the uncertainty of future cash flows, HEI is accounting for the income notes under the cost recovery method of accounting. In the second half of 2001 and in 2002, HEI recognized a $5.6 million ($8.7 million pretax) and a $2.9 million ($4.5 million pretax), respectively, net loss on the writedown of the three income notes to their then-current estimated fair value based upon an independent third party valuation that is updated quarterly. As of December 31, 2002, the estimated fair value and carrying value (including valuation adjustments) of the income notes totaled approximately $8.0 million. HEI could incur additional losses from the ultimate disposition of these income notes due to further “other-than-temporary” declines in their fair value. ASB has agreed to indemnify HEI against losses related to these income notes, but the indemnity obligation is payable solely out of any recoveries achieved in the litigation against PaineWebber Incorporated. In 2002, PaineWebber Incorporated filed a counterclaim alleging misrepresentation and fraud among other allegations. In January 2003, a hearing on several motions for partial summary judgment was held. The Court denied all motions, except for a ruling that PaineWebber did not owe a fiduciary duty to ASB with respect to two of the three transactions. The Company has filed a motion for reconsideration on this ruling. All other claims and issues were reserved for the trial, which is scheduled to begin in July 2003. Additional discovery and pretrial motion work is anticipated prior to trial. The ultimate outcome of this litigation cannot be determined at this time.

Loans receivable

December 31	2002			2001
(in thousands)
Real estate loans
One-to-four unit residential and commercial	$	2,526,505		$	2,408,177
Construction and development		46,150			52,043
		2,572,655			2,460,220
Loans secured by savings deposits		8,034			7,288
Consumer loans		237,819			245,199
Commercial loans		247,114			197,333
		3,065,622			2,910,040
Undisbursed portion of loans in process		(21,413	)		(22,915	)
Deferred fees and discounts, including net purchase accounting discounts		(19,180	)		(17,946	)
Allowance for loan losses		(45,435	)		(42,224	)
Loans held to maturity		2,979,594			2,826,955
Residential loans held for sale		14,395			29,248
Commercial real estate loans held for sale		—			1,419
	$	2,993,989		$	2,857,622

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At December 31, 2002 and 2001, the weighted-average interest rate for loans receivable was 6.52% and 7.25%, respectively.

At December 31, 2002, ASB had pledged loans with an amortized cost of approximately $1.4 billion as collateral to secure advances from the FHLB of Seattle.

At December 31, 2002 and 2001, the aggregate amount of loans to directors and executive officers of ASB and its affiliates and any related interests (as defined in Federal Reserve Board Regulation O) of such individuals, was $61 million and $19 million, respectively. Of the $42 million increase in such loans in 2002, $25 million were primarily attributed to existing loans of a new ASB director’s related interest and $17 million related to new loans made to related interests of directors of ASB. At December 31, 2002 and 2001, $50 million and $10 million of the loan balances, respectively, were to related interests of individuals who are directors of ASB. All such loans were made at ASB’s normal credit terms except that residential real estate loans and consumer loans to directors and executive officers of ASB were made at preferred employee interest rates. In ASB’s opinion, these loans do not represent more than a normal risk of collection.

At December 31, 2002, ASB had impaired loans totaling $22.2 million, which consisted of $10.7 million of income property loans and $11.5 million of commercial loans. At December 31, 2001, ASB had impaired loans totaling $20.3 million, which consisted of $14.6 million of income property loans, $0.2 million of residential real estate loans for properties of one-to-four units and $5.5 million of commercial loans. The average balances of impaired loans during 2002, 2001 and 2000 were $26.0 million, $23.2 million and $36.0 million, respectively. At December 31, 2002, 2001 and 2000, the allowance for loan losses for impaired loans was $0.3 million, $3.7 million and $4.8 million, respectively.

At December 31, 2002 and 2001, ASB had nonaccrual and renegotiated loans of $26 million and $44 million, respectively.

ASB realized $0.4 million, $1.5 million and $1.9 million of interest income on nonaccrual loans in 2002, 2001 and 2000, respectively. If these loans would have earned interest in accordance with their original contractual terms ASB would have realized $0.9 million, $2.2 million and $2.8 million in 2002, 2001 and 2000, respectively.

ASB services real estate loans owned by third parties ($0.9 billion, $1.1 billion and $0.6 billion at December 31, 2002, 2001 and 2000, respectively), which are not included in the accompanying consolidated financial statements. ASB reports fees earned for servicing loans as income when the related mortgage loan payments are collected and charges loan servicing costs to expense as incurred.

At December 31, 2002 and 2001, commitments not reflected in the consolidated balance sheets consisted of: commitments to originate loans, other than loans in process, of $69.4 million and $40.8 million, respectively; standby, commercial and banker’s acceptance letters of credit of $11.2 million and $9.6 million, respectively; and unused lines of credit of $690.3 million and $652.8 million, respectively.

Allowance for loan losses. Changes in the allowance for loan losses were as follows:

Years ended December 31,	2002			2001			2000
(dollars in thousands)
Allowance for loan losses, January 1	$	42,224		$	37,449		$	35,348
Provision for loan losses		9,750			12,500			13,050
Net charge-offs
Real estate loans		1,876			3,414			6,727
Other loans		4,663			4,311			4,222
Total net charge-offs		6,539			7,725			10,949
Allowance for loan losses, December 31	$	45,435		$	42,224		$	37,449
Ratio of allowance for loan losses, December 31, to average loans outstanding		1.60	%		1.42	%		1.16	%
Ratio of provision for loan losses during the year to average loans outstanding		0.34	%		0.42	%		0.41	%
Ratio of net charge-offs during the year to average loans outstanding		0.23	%		0.26	%		0.34	%

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Real estate acquired in settlement of loans. At December 31, 2002 and 2001, ASB’s real estate acquired in settlement of loans was $12.1 million and $14.5 million, respectively.

Deposit liabilities

December 31	2002				2001
(in thousands)	Weighted- average stated rate		Amount		Weighted- average stated rate		Amount
Commercial checking	—	%	$	241,996	—	%	$	144,885
Other checking	0.13			620,631	0.21			625,248
Passbook	0.75			1,226,337	1.50			1,104,725
Money market	1.04			442,735	1.79			337,997
Term certificates	3.80			1,269,073	4.43			1,466,731
	1.65	%	$	3,800,772	2.42	%	$	3,679,586

At December 31, 2002 and 2001, deposit accounts of $100,000 or more totaled $0.8 billion and $0.7 billion, respectively.

The approximate amounts of term certificates outstanding at December 31, 2002 with scheduled maturities for 2003 through 2007 were $505.7 million in 2003, $291.7 million in 2004, $301.7 million in 2005, $63.5 million in 2006 and $55.2 million in 2007.

Interest expense on savings deposits by type of deposit was as follows:

Years ended December 31	2002		2001		2000
(in thousands)
Interest-bearing checking	$	1,059	$	4,150	$	5,484
Passbook		14,512		20,004		21,186
Money market		6,092		7,432		9,015
Term certificates		51,968		84,945		83,507
	$	73,631	$	116,531	$	119,192

Securities sold under agreements to repurchase

December 31, 2002
Maturity	Repurchase liability		Weighted-average interest rate		Collateralized by mortgage-related securities–fair value plus accrued interest
(in thousands)
Overnight	$	34,845	1.15	%	$	42,072
1 to 29 days		60,077	1.39			71,680
30 to 90 days		116,599	2.23			128,343
Over 90 days		455,726	3.80			546,122
	$	667,247	3.17	%	$	788,217

At December 31, 2002, securities sold under agreements to repurchase consisted of mortgage-related securities sold under fixed-coupon agreements. The FHLMC, GNMA and FNMA mortgage-related securities are book-entry securities and were delivered by appropriate entry into the counterparties’ accounts at the Federal Reserve System. The remaining securities underlying the agreements were delivered to the brokers/dealers who arranged the transactions. The carrying value of securities underlying the agreements remained in ASB’s asset accounts and the obligation to repurchase securities sold is reflected as a liability in the consolidated balance sheet. At December 31, 2002 and 2001, ASB had agreements to repurchase identical securities totaling $667 million and $683 million, respectively. At December 31, 2002 and 2001, the weighted-average rate on securities sold under agreements to repurchase was 3.17% and 2.81%, respectively, and the weighted-average remaining days to maturity was 454 days and 114 days, respectively. During 2002, 2001 and 2000, securities sold under agreements

66

to repurchase averaged $663 million, $629 million and $625 million, respectively, and the maximum amount outstanding at any month-end was $751 million, $722 million and $657 million, respectively.

Advances from Federal Home Loan Bank

December 31	2002				2001
(in thousands)	Weighted- average stated rate		Amount		Weighted- average stated rate		Amount
Due in
2002	NA			NA	3.91	%	$	172,800
2003	4.58	%	$	272,700	4.96			252,700
2004	4.95			329,321	5.36			264,321
2005	5.98			382,231	6.48			308,931
2006	6.70			36,000	6.93			34,000
2007	3.81			156,000	—			—
	5.10	%	$	1,176,252	5.41	%	$	1,032,752

NA Not applicable.

Advances from the FHLB of Seattle are secured by mortgage-related securities, loans and stock in the FHLB of Seattle. As a member of the FHLB system, ASB is required to own a specific number of shares of capital stock of the FHLB of Seattle.

Common stock equity. As of December 31, 2002, ASB was in compliance with the minimum capital requirements under OTS regulations. HEI agreed with the OTS predecessor regulatory agency that it would contribute additional capital to ASB up to a maximum aggregate amount of approximately $65 million. As of December 31, 2002, HEI’s maximum obligation to contribute additional capital has been reduced to approximately $28 million.

5 • Short-term borrowings

No commercial paper was outstanding at December 31, 2002 and 2001.

At December 31, 2002 and 2001, HEI maintained bank lines of credit which totaled $70 million ($30 million maturing in April 2003, $30 million in June 2003 and $10 million in October 2003) and $70 million, respectively, and HECO maintained bank lines of credit which totaled $100 million ($20 million maturing in March 2003, $30 million in April 2003, $10 million in May 2003 and $40 million in June 2003) and $110 million, respectively. On January 1, 2003, HECO reduced its total lines of credit to $90 million, thereby reducing to $30 million the HECO lines maturing in June 2003. HEI and HECO maintain lines of credit to support the issuance of commercial paper and for other general corporate purposes. None of the lines are secured. HECO borrowed and repaid $8.8 million under a line of credit in 2001. There were no borrowings under any line of credit at December 31, 2001 or during 2002.

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6 • Long-term debt

December 31	2002			2001
(in thousands)
HELCO first mortgage bonds – 7.75-7.88%, paid in 2002	$	—		$	5,000
Obligations to the State of Hawaii for the repayment of special purpose revenue bonds issued on behalf of electric utility subsidiaries
4.95%, due 2012		57,500			57,500
5.45-7.60%, due 2020-2023		240,000			240,000
5.65-6.60%, due 2025-2027		272,000			272,000
5.50-6.20%, due 2014-2029		116,400			116,400
5.10%, due 2032		40,000			—
		725,900			685,900
Less funds on deposit with trustees		(16,111	)		(10,808	)
Less unamortized discount		(4,519	)		(4,418	)
		705,270			670,674
Promissory notes
Variable rate (5.54% at December 31, 2002), due in 2003		100,000			100,000
7.9% note, paid in 2002		—			9,595
6.15-7.56%, due in various years through 2014		301,000			360,500
		401,000			470,095
	$	1,106,270		$	1,145,769

At December 31, 2002, the aggregate principal payments required on long-term debt for 2003 through 2007 are $136 million in 2003, $1 million in 2004, $37 million in 2005, $110 million in 2006 and $10 million in 2007.

In January 2003, MECO’s proportionate share of the 6.55% Series 1992 Special Purpose Revenue Bonds, in the principal amount of $8.0 million, was called for redemption on March 12, 2003.

7 • HEI- and HECO-obligated preferred securities of trust subsidiaries

December 31	2002		2001		Liquidation value per security
(in thousands, except per security amounts and number of securities)
Hawaiian Electric Industries Capital Trust I* 8.36% Trust Originated Preferred Securities (4,000,000 securities)**	$	100,000	$	100,000	$	25
HECO Capital Trust I* 8.05% Cumulative Quarterly Income Preferred Securities, Series 1997 (2,000,000 securities)***		50,000		50,000		25
HECO Capital Trust II* 7.30% Cumulative Quarterly Income Preferred Securities, Series 1998 (2,000,000 securities)****		50,000		50,000		25
	$	200,000	$	200,000

* Delaware grantor trust.

** No scheduled maturity. Redeemable at the issuer’s option after February 4, 2002.

*** Mandatorily redeemable at the maturity of the underlying debt on March 27, 2027, which maturity may be extended to no later than March 27, 2046. Also, redeemable at the issuer’s option after March 27, 2002.

**** Mandatorily redeemable at the maturity of the underlying debt on December 15, 2028, which maturity may be extended to no later than December 15, 2047. Also, redeemable at the issuer’s option after December 15, 2003.

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8 • Retirement benefits

Pensions. Substantially all of the employees of HEI and the utility subsidiaries participate in the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries and substantially all of the employees of ASB and its subsidiaries participate in the American Savings Bank Retirement Plan (collectively, Plans). The Plans are qualified, non-contributory defined benefit pension plans with the benefits for union employees determined in accordance with the terms of the collective bargaining agreements between the utilities and their respective unions. The Plans are subject to the provisions of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In addition, some current and former executives and directors of HEI and its subsidiaries participate in noncontributory, nonqualified plans (collectively, Supplemental/Excess/Directors Plans). In general, benefits are based on the employees’ years of service and compensation.

The Plans and the Supplemental/Excess/Directors Plans were adopted with the expectation that they will continue indefinitely, but the continuation of these plans and the payment of any contribution thereunder is not assumed as a contractual obligation by the participating employers. Each participating employer reserves the right to terminate its participation in the applicable plan at any time, and HEI and ASB reserve the right to terminate their respective plan at any time. If a participating employer terminated its participation in the Plans, the interest of each affected participant would become 100% vested to the extent funded. Upon the termination of the Plans, assets would be distributed to affected participants in accordance with the applicable allocation provisions of ERISA and any excess assets that exist would be paid to the Participating Employers. Participants’ benefits are covered up to certain limits under insurance provided by the Pension Benefit Guaranty Corporation (PBGC).

The Participating Employers contribute amounts to a master pension trust (Trust) for the Plans in accordance with the funding requirements of ERISA and considering the deductibility of contributions under the Internal Revenue Code (Code). The funding of the Plans is based on actuarial assumptions adopted by the Pension Investment Committee administering the Plans on the advice of an enrolled actuary.

To determine pension costs for HEI and its subsidiaries under the Plans and the Supplemental/Excess/Directors Plans, it is necessary to make complex calculations and estimates based on numerous assumptions, including the weighted-average assumptions identified below.

Postretirement benefits other than pensions. HEI and the electric utility subsidiaries provide eligible employees health and life insurance benefits upon retirement under the Postretirement Welfare Benefits Plan for Employees of Hawaiian Electric Company, Inc. and Participating Employers. The amount of health benefits is based on retirees’ years of service and retirement date. Generally, employees are eligible for these benefits if, upon retirement, they participate in the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries.

The postretirement benefits plan was adopted with the expectation that it will continue indefinitely, but the continuation of the plan and the payment of any contribution thereunder is not assumed as a contractual obligation by the participating employers. Each participating employer reserves the right to terminate its participation in the postretirement benefits plan at any time.

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Pension and other postretirement benefit plans information. The changes in the pension and other postretirement benefit defined benefit plans’ obligations and plan assets, the funded status of the plans and the unrecognized and recognized amounts reflected in the balance sheet were as follows:

	Pension benefits						Other benefits
(in thousands)	2002			2001			2002			2001
Benefit obligation, January 1	$	646,197		$	599,669		$	146,486		$	124,924
Service cost		20,215			19,390			3,135			3,051
Interest cost		45,806			43,512			10,158			9,348
Amendments		(34	)		247			—			222
Actuarial loss		52,597			17,475			6,051			15,576
Benefits paid		(36,001	)		(34,096	)		(6,400	)		(6,635	)
Benefit obligation, December 31		728,780			646,197			159,430			146,486
Fair value of plan assets, January 1		719,112			836,910			90,041			104,099
Actual loss on plan assets		(97,541	)		(84,274	)		(14,169	)		(11,457	)
Employer contribution		3,522			572			6,454			4,034
Benefits paid		(36,001	)		(34,096	)		(6,400	)		(6,635	)
Fair value of plan assets, December 31		589,092			719,112			75,926			90,041
Funded status		(139,688	)		72,915			(83,504	)		(56,445	)
Unrecognized net actuarial loss (gain)		209,828			(24,756	)		24,361			(6,599	)
Unrecognized net transition obligation		981			3,251			32,781			36,059
Unrecognized prior service cost (gain)		(6,999	)		(7,470	)		196			209
Net amount recognized, December 31	$	64,122		$	43,940		$	(26,166	)	$	(26,776	)
Amounts recognized in the balance sheet consist of:
Prepaid benefit cost	$	70,328		$	51,894		$	—		$	—
Accrued benefit liability		(15,063	)		(9,313	)		(26,166	)		(26,776	)
Intangible asset		690			7			—			—
Accumulated other comprehensive income		8,167			1,352			—			—
Net amount recognized, December 31	$	64,122		$	43,940		$	(26,166	)	$	(26,776	)

The following weighted-average assumptions were used in the accounting for the plans:

	Pension benefits						Other benefits
December 31	2002		2001		2000		2002		2001		2000
Discount rate	6.75	%	7.25	%	7.50	%	6.75	%	7.25	%	7.50	%
Expected return on plan assets	9.0		10.0		10.0		9.0		10.0		10.0
Rate of compensation increase	4.6		4.6		4.6		4.6		4.6		4.6

At December 31, 2002, the assumed health care trend rates for 2003 and future years were as follows: medical, 9.28%, grading down to 4.25%; dental, 4.25%; and vision, 3.25%. At December 31, 2001, the assumed health care trend rates for 2002 and future years were as follows: medical, 10.00%, grading down to 4.75%; dental, 4.75%; and vision, 3.75%.

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The components of net periodic benefit cost (return) were as follows:

	Pension benefits									Other benefits
Years ended December 31	2002			2001			2000			2002			2001			2000
(in thousands)
Service cost	$	20,215		$	19,390		$	18,254		$	3,135		$	3,051		$	2,832
Interest cost		45,806			43,512			41,656			10,158			9,348			8,938
Expected return on plan assets		(80,958	)		(80,281	)		(74,708	)		(10,023	)		(10,032	)		(9,327	)
Amortization of unrecognized transition obligation		2,270			2,326			2,326			3,278			3,278			3,278
Amortization of prior service cost (gain)		(505	)		(482	)		(413	)		13			13			–
Recognized actuarial gain		(3,489	)		(8,183	)		(9,438	)		(716	)		(2,599	)		(3,113	)
Net periodic benefit cost (return)	$	(16,661	)	$	(23,718	)	$	(22,323	)	$	5,845		$	3,059		$	2,608

Of the net periodic pension benefit costs (returns), the Company recorded income of $11 million in 2002, $17 million in 2001 and 2000, and credited the remaining amounts primarily to electric utility plant. Of the net periodic other benefit costs, the Company expensed $4 million, $2 million and $2 million in 2002, 2001 and 2000, respectively, and charged the remaining amounts primarily to electric utility plant.

The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for pension plans with an accumulated benefit obligation in excess of plan assets were $55 million, $42 million and $29 million, respectively, as of December 31, 2002 and $9 million, $8 million and nil, respectively, as of December 31, 2001.

The health care cost trend rate assumptions can have a significant effect on the amounts reported for other benefits. At December 31, 2002, a one-percentage-point increase in the assumed health care cost trend rates would have increased the total service and interest cost by $0.3 million and the postretirement benefit obligation by $3.8 million, and a one-percentage-point decrease would have reduced the total service and interest cost by $0.3 million and the postretirement benefit obligation by $4.5 million.

9 • Income taxes

The components of income taxes attributable to income from continuing operations were as follows:

Years ended December 31	2002			2001			2000
(in thousands)
Federal
Current	$	24,791		$	56,648		$	51,702
Deferred		35,614			(730	)		6,230
Deferred tax credits, net		(1,557	)		(1,567	)		(1,585	)
		58,848			54,351			56,347
State
Current		2,668			248			2,968
Deferred		1,139			1,112			912
Deferred tax credits, net		1,037			2,446			932
		4,844			3,806			4,812
	$	63,692		$	58,157		$	61,159

In March 1998, ASB formed a subsidiary, ASB Realty Corporation, which elects to be taxed as a real estate investment trust. This reorganization has reduced Hawaii bank franchise taxes, net of federal income taxes, of HEI Diversified, Inc. (HEIDI) and ASB by $17 million for 2002 and prior years. ASB has taken a dividends received deduction on dividends paid to it by ASB Realty Corporation in the returns filed in 1999 through 2002. The State of Hawaii Department of Taxation has challenged ASB’s position and has issued notices of tax assessment for 1999, 2000 and 2001. The aggregate amount of tax assessments is approximately $14 million (or $9 million, net of income tax benefits) for tax years 1999 through 2001, plus interest of $3 million (or $2 million, net of income tax benefits) through December 31, 2002. The interest on the tax is accruing at a simple interest rate of 8%. Although

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not yet assessed, the potential bank franchise tax liability for 2002 if ASB’s tax position does not prevail is $6 million (or $4 million, net of income tax benefits), plus interest of $0.3 million through December 31, 2002. ASB believes that its tax position is proper and, in October 2002, filed an appeal with the State Board of Review, First Taxation District. No provision for Hawaii bank franchise taxes has been made since 1998.

A reconciliation of the amount of income taxes computed at the federal statutory rate of 35% to the amount provided in the Company’s consolidated statements of income was as follows:

Years ended December 31	2002			2001			2000
(in thousands)
Amount at the federal statutory income tax rate	$	63,668		$	58,066		$	59,673
Increase (decrease) resulting from:
State income taxes, net of effect on federal income taxes		3,149			2,474			3,129
Preferred stock dividends of subsidiaries		698			698			698
Other, net		(3,823	)		(3,081	)		(2,341	)
	$	63,692		$	58,157		$	61,159

The tax effects of book and tax basis differences that give rise to deferred tax assets and liabilities were as follows:

December 31	2002		2001
(in thousands)
Deferred tax assets
Property, plant and equipment	$	12,894	$	13,654
Contributions in aid of construction and customer advances		46,052		47,546
Allowance for loan losses		15,783		17,740
Other		29,963		29,222
		104,692		108,162
Deferred tax liabilities
Property, plant and equipment		174,924		170,561
Leveraged leases		35,796		38,398
Real estate investment trust dividends (federal income taxes only)		28,409		–
Net unrealized gains on available-for-sale mortgage-related securities		16,888		3,467
Regulatory assets		24,794		24,313
FHLB stock dividend		16,547		16,458
Other		42,765		40,401
		340,123		293,598
Net deferred income tax liability	$	235,431	$	185,436

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. Based upon historical taxable income, projections for future taxable income and available tax planning strategies, management believes it is more likely than not the Company will realize the benefits of the deferred tax assets and has provided no valuation allowance for deferred tax assets during 2002, 2001 and 2000.

10 • Cash flows

Supplemental disclosures of cash flow information. In 2002, 2001 and 2000, the Company paid interest amounting to $225 million, $293 million and $309 million, respectively.

In 2002, 2001 and 2000, the Company paid income taxes amounting to $60 million, $30 million and $11 million, respectively.

Supplemental disclosures of noncash activities. In April 2000, HEI recommenced issuing new common shares under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP). From March 1998 to March 2000, HEI had acquired for cash its common shares in the open market to satisfy the requirements of the HEI DRIP. Under the

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HEI DRIP, common stock dividends reinvested by shareholders in HEI common stock in noncash transactions amounted to $17 million in 2002, $16 million in 2001 and $12 million in 2000.

ASB received $0.4 billion in mortgage-related securities in exchange for loans in 2001.

In 2002, 2001 and 2000, HECO and its subsidiaries capitalized as part of the cost of electric utility plant an allowance for equity funds used during construction amounting to $4 million, $4 million and $5 million, respectively.

The estimated fair value of noncash contributions in aid of construction amounted to $4 million, $2 million and $7 million in 2002, 2001 and 2000, respectively.

In 2002, HECO assigned account receivables totaling $10 million to a creditor, without recourse, in full settlement of HECO’s $10 million notes payable to that creditor.

11 • Regulatory restrictions on net assets

At December 31, 2002, HECO and its subsidiaries could not transfer approximately $452 million of net assets to HEI in the form of dividends, loans or advances without regulatory approval.

ASB is required to file a notice with the OTS 30 days prior to making any capital distribution to HEI. Generally, the OTS may disapprove or deny ASB’s notice of intention to make a capital distribution if the proposed distribution will cause ASB to become undercapitalized, or the proposed distribution raises safety and soundness concerns, or the proposed distribution violates a prohibition contained in any statue, regulation, or agreement between ASB and the OTS. At December 31, 2002, ASB could transfer approximately $104 million of net assets to HEI in the form of dividends and still maintain its “well-capitalized” position.

HEI management expects that the regulatory restrictions will not materially affect the operations of the Company nor HEI’s ability to pay common stock dividends.

12 • Significant group concentrations of credit risk

Most of the Company’s business activity is with customers located in the State of Hawaii. Most of ASB’s financial instruments are based in the State of Hawaii, except for the mortgage-related securities it owns. Substantially all real estate loans receivable are secured by real estate in Hawaii. ASB’s policy is to require mortgage insurance on all real estate loans with a loan to appraisal ratio in excess of 80% at origination. At December 31, 2002, ASB’s private-issue mortgage-related securities represented whole or participating interests in pools of mortgage loans collateralized by real estate in the continental U.S. As of December 31, 2002, various securities rating agencies rated the private-issue mortgage-related securities held by ASB as investment grade.

13 • Discontinued operations

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

Guam project. In September 1996, HEI Power Corp. Guam (HPG) entered into an energy conversion agreement for approximately 20 years with the Guam Power Authority, pursuant to which HPG repaired and operated two oil-fired 25 MW (net) units in Tanguisson, Guam. In November 2001, HEI sold HPG for a nominal gain. In the stock purchase agreement, HEIPC agreed to indemnify the purchaser of HPG with respect to representations, warranties and covenants made by HEIPC (e.g., that the project and project site suffered from no environmental liabilities except as disclosed and that HEIPC would bear the risk that the final provisions of a required air permit would be more onerous than the preliminary draft provided at closing). No amounts have been accrued related to the indemnities and the maximum potential exposure is estimated to be the sales price of $13 million.

China project. In 1998 and 1999, the HEIPC Group acquired what became a 75% interest in a joint venture, Baotou Tianjiao Power Co., Ltd., formed to construct, own and operate a 200 MW (net) coal-fired power plant to be located in Inner Mongolia. The power plant was intended to be built “inside the fence” for Baotou Iron & Steel (Group) Co., Ltd. The project received approval from both the national and Inner Mongolia governments. However, the Inner Mongolia Power Company, which owns and operates the electricity grid in Inner Mongolia, caused a delay

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of the project by failing to enter into a satisfactory interconnection arrangement with the joint venture. The Inner Mongolia Power Company was seeking to limit the joint venture’s load, which is inconsistent with the terms of the project approvals and the power purchase contract. Upon appeal to the Inner Mongolia government, the Inner Mongolia Economic and Trade Committee (the regulator of the electric utility industry) refused to enforce the HEIPC Group’s rights associated with the approved project. The HEIPC Group determined that a satisfactory interconnection arrangement could not be obtained and is not proceeding with the project. (An indirect subsidiary of HEIPC has a conditional, nonrecourse commitment to make an additional investment in Baotou Tianjiao Power Co., Ltd., but it is HEIPC’s position that the conditions to this commitment have not been satisfied and no further investment will be made.) In the third quarter of 2001, the HEIPC Group wrote off its remaining investment of approximately $24 million in the project. The HEIPC Group is continuing to pursue recovery of the costs incurred in connection with the joint venture interest; however, there can be no assurance that any amount will be recovered and no recovery has been accrued on the financial statements of the Company.

Philippines investments. In March 2000, the HEIPC Group acquired a 50% interest in EPHE Philippines Energy Company, Inc. (EPHE), an indirect subsidiary of El Paso Corporation, for $87.5 million. EPHE then owned approximately 91.7% of the common shares of East Asia Power Resources Corporation (EAPRC), a Philippines holding company primarily engaged in the electric generation business in Manila and Cebu through its subsidiaries.

Due to the equity losses of $24.1 million incurred in 2000 from the investment in EPHE and the changes in the political and economic conditions related to the investment (primarily devaluation of the Philippine peso and increase in fuel oil prices), management determined that the investment in EAPRC was impaired and, on December 31, 2000, wrote off the remaining $65.7 million investment in EAPRC. Also, on December 31, 2000, HEI accrued a potential payment obligation under an HEI guaranty of $10 million of EAPRC loans. In the first quarter of 2001, HEI was partially released ($1.5 million) from the guaranty obligation; and, in August 2002, HEI paid approximately $8.5 million in full satisfaction of such obligation. The indirect subsidiary of HEIPC which held the shares in EPHE has been dissolved and those shares were cancelled by a reduction of the capital stock of EPHE approved by the Philippine Securities and Exchange Commission.

In December 1998, the HEIPC Group invested $7.6 million to acquire convertible preferred shares in Cagayan Electric Power & Light Co., Inc. (CEPALCO), an electric distribution company in the Philippines. In September 1999, the HEIPC Group also acquired 5% of the outstanding CEPALCO common stock for $2.1 million. In July 2001, the preferred shares were converted to common stock. The HEIPC Group currently owns approximately 22% of the outstanding common stock of CEPALCO. This investment is classified as available for sale. The HEIPC Group recognized an impairment loss of approximately $2.7 million in the third quarter of 2001 to adjust this investment to its estimated net realizable value.

Summary financial information for the discontinued operations of the HEIPC Group is as follows:

Years ended December 31	2001			2000
(in thousands)
Operations
Revenues (including equity losses)	$	4,233		$	(13,287	)
Operating loss		(233	)		(102,185	)
Interest expense		(1,050	)		(1,324	)
Income tax benefits		29			39,917
Loss from operations		(1,254	)		(63,592	)
Disposal
Loss, including provision of $7,995 for losses from operations during phase-out period		(34,784	)		—
Income tax benefits		12,463			—
Loss on disposal		(22,321	)		—
Loss from discontinued operations of HEIPC	$	(23,575	)	$	(63,592	)

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As of December 31, 2002, the remaining net assets of the discontinued international power operations, after the write-offs and writedowns described above, amounted to $13 million (included in “Other” assets) and consisted primarily of the $7 million investment in CEPALCO and deferred taxes receivable, reduced by a reserve for losses from operations during the phase-out period. The amounts that HEIPC will ultimately realize from the disposition or sale of the international power assets could differ materially from the recorded amounts. This could occur, for example, if the HEIPC Group is successful in recovery of the costs incurred in connection with the China joint venture interest, if the investment in CEPALCO is disposed of for less or more than $7 million or if the Internal Revenue Service does not accept HEI’s treatment of the write-off of its indirect investment in EAPRC as an ordinary loss for federal corporate income tax purposes. In addition, further losses from the discontinued international power operations may be sustained during the phase-out period if the expenditures made in seeking recovery of the costs incurred in connection with the China joint venture interest exceed the total of any recovery ultimately achieved and the amount provided for in HEI’s reserve for discontinued operations.

Malama Pacific Corp. (MPC). On September 14, 1998, the HEI Board of Directors adopted a plan to exit the residential real estate development business (engaged in by MPC and its subsidiaries). Accordingly, MPC management commenced a program to sell all of MPC’s real estate assets and investments and HEI reported MPC as a discontinued operation in the Company’s consolidated statements of income in 1998. Operating activity of the residential real estate development business for the period September 14, 1998 through December 31, 2002 was not significant. In 2001, deferred tax assets and final offsite obligations on properties previously sold were adjusted, and the Company increased the loss reserve by $0.5 million.

As of December 31, 2002, the remaining net assets of the discontinued residential real estate development operations amounted to $4 million (included in “Other” assets) and consisted primarily of receivables and deferred tax assets. The amounts that MPC will ultimately realize from these assets could differ materially from the recorded amounts.

14 • Fair value of financial instruments

The Company used the following methods and assumptions to estimate the fair value of each applicable class of financial instruments for which it is practicable to estimate that value:

Cash and equivalents and short-term borrowings. The carrying amount approximated fair value because of the short maturity of these instruments.

Investment and mortgage-related securities. Fair value was based on quoted market prices or dealer quotes or estimated by discounting the expected future cash flows using current market rates for similar investments.

Loans receivable. For certain categories of loans, such as some residential mortgages, credit card receivables, and other consumer loans, fair value was estimated using the quoted market prices for securities backed by similar loans, adjusted for differences in loan characteristics and estimated servicing. The fair value of other types of loans was estimated by discounting the future cash flows using the current rates at which similar loans would be made to borrowers with similar credit ratings and for similar remaining maturities.

Deposit liabilities. The fair value of demand deposits, savings accounts, and money market deposits was the amount payable on demand at the reporting date. The fair value of fixed-maturity certificates of deposit was estimated by discounting the future cash flows using the rates currently offered for deposits of similar remaining maturities.

Securities sold under agreements to repurchase. Fair value was estimated by discounting future cash flows using the current rates available for repurchase agreements with similar terms and remaining maturities.

Advances from Federal Home Loan Bank and long-term debt. Fair value was estimated by discounting the future cash flows using the current rates available for borrowings with similar remaining maturities.

HEI- and HECO-obligated preferred securities of trust subsidiaries. Fair value was based on quoted market prices.

Off-balance sheet financial instruments. The fair values of off-balance sheet financial instruments were estimated based on the fees currently charged to enter into similar agreements, taking into account the remaining

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terms of the agreements and the present creditworthiness of the counterparties, current settlement values or quoted market prices of comparable instruments.

The estimated fair values of certain of the Company’s financial instruments were as follows:

December 31	2002				2001
(in thousands)	Carrying or notional amount		Estimated fair value		Carrying or notional amount		Estimated fair value
Financial assets
Cash and equivalents	$	244,525	$	244,525	$	450,827	$	450,827
Available-for-sale investment and mortgage-related securities		2,744,650		2,744,650		2,370,459		2,370,459
Held-to-maturity investment securities		89,545		89,545		84,211		84,211
Loans receivable, net		2,993,989		3,108,659		2,857,622		2,965,857
Financial liabilities
Deposit liabilities		3,800,772		3,838,317		3,679,586		3,702,717
Securities sold under agreements to repurchase		667,247		685,022		683,180		684,543
Advances from Federal Home Loan Bank		1,176,252		1,248,001		1,032,752		1,078,744
Long-term debt		1,106,270		1,146,368		1,145,769		1,114,032
HEI- and HECO-obligated preferred securities of trust subsidiaries		200,000		200,720		200,000		201,520
Off-balance sheet items
Loans serviced for others		887,158		6,776		1,057,273		13,186
Unused lines and letters of credit		701,467		44,539		662,428		21,582

At December 31, 2002 and 2001, neither the commitment fees received on commitments to extend credit nor the fair value thereof were significant to the Company’s consolidated financial statements.

Limitations. The Company makes fair value estimates at a specific point in time, based on relevant market information and information about the financial instrument. These estimates do not reflect any premium or discount that could result if the Company were to sell its entire holdings of a particular financial instrument at one time. Because no market exists for a significant portion of the Company’s financial instruments, fair value estimates cannot be determined with precision. Changes in assumptions could significantly affect the estimates.

Fair value estimates are provided for certain financial instruments without attempting to estimate the value of anticipated future business and the value of assets and liabilities that are not considered financial instruments. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates and have not been considered.

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15 • Quarterly information (unaudited)

Selected quarterly information was as follows:

	Quarters ended												Year ended December 31
(in thousands, except per share amounts)	March 31			June 30			Sept. 30			Dec.31
2002
Revenues	$	377,436		$	409,002		$	431,560		$	435,703		$	1,653,701
Operating income 1		64,604			70,626			71,738			59,465			266,433
Net income 1		26,872			31,458			33,512			26,375			118,217
Basic earnings per common share3		0.75			0.87			0.92			0.72			3.26
Diluted earnings per common share4		0.75			0.86			0.91			0.72			3.24
Dividends per common share		0.62			0.62			0.62			0.62			2.48
Market price per common share 5
High		44.45			47.80			46.98			49.00			49.00
Low		39.35			41.50			34.55			41.73			34.55
2001
Revenues	$	433,337		$	427,339		$	447,292		$	419,309		$	1,727,277
Operating income 1		64,934			64,700			69,051			57,488			256,173
Net income 1
Continuing operations		27,764			26,112			28,666			25,204			107,746
Discontinued operations 2		(19	)		(524	)		(21,532	)		(1,966	)		(24,041	)
		27,745			25,588			7,134			23,238			83,705
Basic earnings (loss) per common share 3
Continuing operations		0.84			0.78			0.85			0.73			3.19
Discontinued operations 2		—			(0.02	)		(0.64	)		(0.06	)		(0.71	)
		0.84			0.76			0.21			0.67			2.48
Diluted earnings (loss) per common share 4
Continuing operations		0.83			0.78			0.84			0.73			3.18
Discontinued operations 2		—			(0.02	)		(0.63	)		(0.06	)		(0.71	)
		0.83			0.76			0.21			0.67			2.47
Dividends per common share		0.62			0.62			0.62			0.62			2.48
Market price per common share 5
High		37.75			38.40			41.25			40.90			41.25
Low		33.56			35.75			36.12			36.80			33.56

1 For 2002, amounts reflect stock option compensation expense under the fair value based method of accounting prescribed by SFAS No. 123, as amended. For 2001, amounts reflect stock option compensation expense under the intrinsic value-based method of accounting prescribed by APB Opinion No. 25 and related interpretations. Also, for 2002, goodwill is no longer amortized as prescribed by SFAS No. 142.

2 For 2001, amounts for the third quarter include the write-off of the China project, writedown of an investment in CEPALCO and establishment of a reserve for losses from operations during the phase-out period of the discontinued international power operations ($34.8 million pretax, $22.3 million after tax).

3 The quarterly basic earnings (loss) per common share are based upon the weighted-average number of shares of common stock outstanding in each quarter.

4 The quarterly diluted earnings (loss) per common share are based upon the weighted-average number of shares of common stock outstanding in each quarter plus the dilutive incremental shares at quarter end.

5 Market prices of HEI common stock (symbol HE) shown are as reported on the NYSE Composite Tape.

77

The application of SFAS No. 123, as amended, increased net income for the nine months ended September 30, 2002 by $1.2 million, or $0.03 per share. Previously reported net income, and basic and diluted earnings per share for the quarters ended March 31, 2002, June 30, 2002 and September 30, 2002, were restated as follows:

Quarters ended	March 31, 2002			June 30, 2002			September 30, 2002
(in thousands, except per share amounts)
Net income, as reported	$	26,919		$	30,984		$	32,777
Add: Stock option expense included in reported net income, net of tax benefits		131			674			945
Deduct: Total stock option expense determined under the fair value based method, net of tax benefits		(178	)		(200	)		(210	)
Restated net income	$	26,872		$	31,458		$	33,512
Earnings per share
Basic – as reported	$	0.75		$	0.86		$	0.90
Basic – restated	$	0.75		$	0.87		$	0.92
Diluted – as reported	$	0.75		$	0.85		$	0.89
Diluted – restated	$	0.75		$	0.86		$	0.91

78

HEI Directors

Robert F. Clarke, 60 (1)*	T. Michael May, 56*	Oswald K. Stender, 71 (3, 4)
Chairman, President and	President and Chief Executive Officer	Real estate consultant
Chief Executive Officer	Hawaiian Electric Company, Inc.	1993
Hawaiian Electric Industries, Inc.	1995
1989		Kelvin H. Taketa, 48 (2, 3)
	Bill D. Mills, 51 (1, 2, 3, 4)	President and Chief Executive Officer
Don E. Carroll, 61 (2, 3, 4)	Chairman	Hawaii Community Foundation
Chairman	Bill Mills Investment Company	(statewide charitable foundation)
Oceanic Cablevision	(real estate development)	1993
(cable television broadcasting)	1988
1996		Jeffrey N. Watanabe, 60 (1, 4)*
	A. Maurice Myers, 62 (3, 4)	Managing Partner
Shirley J. Daniel, Ph.D., 49 (2)*	Chairman, President and	Watanabe, Ing, Kawashima & Komeiji LLP
Professor of Accountancy	Chief Executive Officer	(private law firm)
University of Hawaii-Manoa	Waste Management, Inc.	1987
College of Business Administration	(environmental services)
(higher education)	1991
2002
	Diane J. Plotts, 67 (1, 2, 3)*
Constance H. Lau, 50*	Business advisor	Committees of the Board of Directors
President and Chief Executive Officer	1987	(1) Executive:
American Savings Bank, F.S.B.		Jeffrey N. Watanabe, Chairman
2001	James K. Scott, Ed.D., 51 (2, 4)*	(2) Audit:
	President	Bill D. Mills, Chairman
Victor Hao Li, S.J.D., 61 (2)	Punahou School	(3) Compensation:
Co-chairman	(private education)	Diane J. Plotts, Chairman
Asia Pacific Consulting Group	1995	(4) Nominating & Corporate Governance:
(international business consultant)		Jeffrey N. Watanabe, Chairman
1988

* Also member of one or more subsidiary boards.

Year denotes year of first election to the board of directors.

Information as of February 12, 2003.

HEI Executive Officers

Robert F. Clarke, 60	Charles F. Wall, 63	T. Michael May, 56 *
Chairman, President and	Vice President and	President and Chief Executive Officer
Chief Executive Officer	Corporate Information Officer	Hawaiian Electric Company, Inc.
1987	1990	1992
Eric K. Yeaman, 35	Andrew I. T. Chang, 63	Constance H. Lau, 50 *
Financial Vice President, Treasurer	Vice President–Government Relations	President and Chief Executive Officer
and Chief Financial Officer	1985	American Savings Bank, F.S.B.
2003		1984
	Curtis Y. Harada, 47
Peter C. Lewis, 68	Controller
Vice President–Administration and	1989
Corporate Secretary
1968

* Deemed to be an executive officer of HEI under SEC Rule 3b-7.

Year denotes year of first employment by the Company.

Information as of February 12, 2003.

79

Stockholder Information

Corporate headquarters

Hawaiian Electric Industries, Inc.

900 Richards Street	P. O. Box 730
Honolulu, Hawaii 96813	Honolulu, Hawaii 96808-0730

Telephone: 808-543-5662

Facsimile: 808-543-7966

New York Stock Exchange

Common stock symbol: HE

Trust preferred securities symbols: HEPrS (HEI),

HEPrQ and HEPrT (HECO)

Shareholder Services

P. O. Box 730

Honolulu, Hawaii 96808-0730

Telephone: 808-532-5841

Facsimile: 808-532-5868

E-mail: invest@hei.com

Office hours: 7:30 a.m. to 4:00 p.m. Hawaii standard time

Correspondence about common stock and utility preferred stock ownership, dividend payments, transfer requirements, changes of address, lost stock certificates, duplicate mailings and account status may be directed to Shareholder Services.

After March 31, 2003, a copy of the Form 10-K annual report for 2002 for Hawaiian Electric Industries, Inc. and Hawaiian Electric Company, Inc., including financial statements and schedules, may be obtained from HEI upon written request without charge from Shareholder Services at the above address or through HEI’s website.

Website

Internet users can access information about HEI and its subsidiaries at http://www.hei.com.

Company news on call

1-888-943-4329 (9HEIFAX)

Our toll free, automated voice response system allows shareholders to listen to recorded dividend and earnings information, news releases, stock quotes and the answers to frequently asked stockholder questions, or to request faxed or mailed copies of various documents.

Dividends and distributions

Common stock quarterly dividends are customarily paid on or about the 10^th of March, June, September and December to stockholders of record on or about the 10^th of February, May, August and November.

Quarterly distributions on trust preferred securities are paid by Hawaiian Electric Industries Capital Trust I and HECO Capital Trusts I and II on or about March 31, June 30, September 30 and December 31 to holders of record on the business day before the distribution is paid.

Utility company preferred stock quarterly dividends are paid on the 15^th of January, April, July and October to preferred stockholders of record on the 5^th of these months.

Dividend reinvestment and stock purchase plan

Any individual of legal age or any entity may buy HEI common stock at market prices directly from the Company. The minimum initial investment is $250. Additional optional cash investments may be as small as $25. The annual maximum investment is $120,000. After your account is open, you may reinvest all of your dividends to purchase additional shares, or elect to receive some or all of your dividends in cash. You may instruct the Company to electronically debit a regular amount from a checking or savings account. The Company also can deposit dividends automatically to your checking or savings account. A prospectus describing the plan may be obtained through HEI’s website or by contacting Shareholder Services.

Annual meeting

Tuesday, April 22, 2003, 9:30 a.m.

American Savings Bank Tower

1001 Bishop Street – 8^th Floor, Room 805

Honolulu, Hawaii 96813

Please direct inquiries to:

Peter C. Lewis

Vice President–Administration and Corporate Secretary

Telephone: 808-543-7900

Facsimile: 808-543-7523

Independent auditors

KPMG LLP

Pauahi Tower

1001 Bishop Street – Suite 2100

Honolulu, Hawaii 96813

Telephone: 808-531-7286

Institutional investor and securities analyst inquiries

Please direct inquiries to:

Suzy P. Hollinger

Manager, Investor Relations

Telephone: 808-543-7385

Facsimile: 808-543-7966

E-mail: shollinger@hei.com

Transfer agents

Common stock and utility company preferred stock:

Shareholder Services

Common stock only:

Continental Stock Transfer & Trust Company

17 Battery Place, 8^th Floor

New York, New York 10004

Telephone: 212-509-4000

Facsimile: 212-509-5150

Trust preferred securities:

Contact your investment broker for information on transfer procedures.

80

EX-13.2

HECO Exhibit 13.2

Contents
Forward-Looking Statements	2
Background of the Company	3
Company Profile	3
Selected Financial Data	4
Management’s Discussion and Analysis of Financial Condition and Results of Operations	5
Quantitative and Qualitative Disclosures about Market Risk	22
Independent Auditors’ Report	23
Consolidated Financial Statements:
Consolidated Statements of Income	24
Consolidated Statements of Retained Earnings	24
Consolidated Balance Sheets	25
Consolidated Statements of Capitalization	26
Consolidated Statements of Cash Flows	28
Notes to Consolidated Financial Statements	29
Consolidated Operating Statistics	58
Directors and Executive Officers	59
Other Stockholder Information	60

1

Forward-Looking Statements

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

• the effects of weather and natural disasters;

• the effects of terrorist acts, the war on terrorism, potential war with Iraq, potential conflict or crisis with North Korea and other global developments;

• the timing and extent of changes in interest rates;

• the risks inherent in changes in the value of pension and other retirement plan assets;

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

• product demand and market acceptance risks;

• increasing competition in the electric utility industry;

• 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 Company 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 Company to negotiate favorable collective bargaining agreements;

• new technological developments that could affect the operations and prospects of the Company or its competitors;

• federal and state governmental and regulatory actions, including changes in laws, rules and regulations applicable to the Company; 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); and changes in taxation;

• the risks associated with the geographic concentration of the Company businesses;

• the effects of changes in accounting principles applicable to the Company;

• the effects of changes by securities rating agencies in the ratings of the securities of the Company;

• the results of financing efforts;

• the ultimate outcome of tax positions taken;

• 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 the Company with the Securities and Exchange Commission.

Forward-looking statements speak only as of the date of the report, presentation or filing in which they are made.

2

Selected Financial Data

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31	2002			2001			2000			1999			1998
(in thousands)
Income statement data
Operating revenues	$	1,252,929		$	1,284,312		$	1,270,635		$	1,050,323		$	1,008,899
Operating expenses		1,117,772			1,148,980			1,137,474			927,482			892,747
Operating income		135,157			135,332			133,161			122,841			116,152
Other income		7,095			7,436			9,935			8,054			16,832
Income before interest and other charges		142,252			142,768			143,096			130,895			132,984
Interest and other charges		50,967			53,388			54,730			54,495			48,754
Income before preferred stock dividends of HECO		91,285			89,380			88,366			76,400			84,230
Preferred stock dividends of HECO		1,080			1,080			1,080			1,178			3,454
Net income for common stock	$	90,205		$	88,300		$	87,286		$	75,222		$	80,776
At December 31	2002			2001			2000			1999			1998
(dollars in thousands)
Balance sheet data
Utility plant	$	3,381,316		$	3,270,855		$	3,162,779		$	3,034,517		$	2,925,344
Accumulated depreciation		(1,367,954	)		(1,266,332	)		(1,170,184	)		(1,076,373	)		(982,172	)
Net utility plant	$	2,013,362		$	2,004,523		$	1,992,595		$	1,958,144		$	1,943,172
Total assets	$	2,436,386		$	2,389,738		$	2,392,858		$	2,302,809		$	2,311,253
Capitalization:1
Short-term borrowings from non-affiliates and affiliate	$	5,600		$	48,297		$	113,162		$	107,013		$	139,413
Long-term debt		705,270			685,269			667,731			646,029			621,998
Preferred stock subject to mandatory redemption		—			—			—			—			33,080
Preferred stock not subject to mandatory redemption		34,293			34,293			34,293			34,293			48,293
HECO-obligated preferred securities of subsidiary trusts		100,000			100,000			100,000			100,000			100,000
Common stock equity		923,256			877,154			825,012			806,103			786,567
Total capitalization	$	1,768,419		$	1,745,013		$	1,740,198		$	1,693,438		$	1,729,351
Capital structure ratios (%)1
Debt		40.2			42.0			44.9			44.5			44.0
Preferred stock		1.9			2.0			2.0			2.0			4.7
HECO-obligated preferred securities of subsidiary trusts		5.7			5.7			5.7			5.9			5.8
Common stock equity		52.2			50.3			47.4			47.6			45.5

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 the “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.

4

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

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

Strategy

The Company’s strategy is to achieve satisfactory returns by containing costs and ensuring customer satisfaction through reliable service and close customer relationships. The success of the Company’s strategy will be heavily influenced by Hawaii’s general economic conditions and tourism. With large power users in the Company’s service territories, such as the U.S. military, hotels and state and local government, management believes that maintaining customer satisfaction is a critical component in achieving kilowatthour (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. Reliability projects remain a priority for the Company. For example, on Oahu, planning has begun for an overhaul and interface of key operating systems, including a new system operations center (subject to approval by the Public Utilities Commission) integrated with new customer information and outage management systems to ensure the most efficient deployment of generators and earlier and faster responses to outages. The Company’s long-term plan to meet Hawaii’s future energy needs also includes its 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.

The Company from time to time considers various strategies designed to enhance its competitive position 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.

Results of operations

Net income for common stock for 2002 was $90.2 million compared to $88.3 million for 2001 and $87.3 million for 2000. The 2002 net income represents a 10.0% return on the average amount of common stock equity invested in the Company, compared to returns of 10.4% in 2001 and 10.7% in 2000. Net income for 2002 increased 2.2% from 2001 as KWH sales increased 1.9% and interest expense decreased 6%. Net income for 2001 increased 1.2% from 2000 due primarily to a 1.1% increase in KWH sales and a HELCO rate increase.

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 in turn is influenced by economic conditions in the mainland U.S. (particularly California) and Asia (particularly Japan) as a result of the impact of those conditions on tourism.

Hawaii’s economy continues to recover from the downturn immediately following the September 11, 2001 terrorist attacks and the weak economic performances in the U.S. mainland and Japan. Hawaii’s real gross state product grew by an estimated 2.1% in 2002, largely driven by a moderate recovery in tourism and continued strength in the local construction and real estate industries. Despite the lagging international market, total visitor arrivals grew 0.9% in 2002 due to strong recovery in the domestic market. Domestic visitor days grew 5% to a record high in 2002 and hotel occupancy increased 1.1% in 2002 over 2001.

The construction and real estate industries, stimulated by low interest rates, also grew in 2002 over strong results in 2001. Construction spending increased by 13.4% for the first 10 months of 2002 and the number of construction jobs increased 3.6% in 2002 over 2001. Private building permits, an indicator of future construction activity, increased by 11.7% in 2002 over 2001. Residential real estate sales also improved in 2002, with Oahu home sales up 14.7% and the median Oahu home resale price up 11.7% over 2001.

Hawaii’s economy is expected to continue to have moderate growth in 2003, barring a war with Iraq, a conflict or crisis with North Korea or other global developments that would heighten international security concerns or

5

derail the modest economic recovery currently underway in the U.S. mainland and Japan. Under this scenario of recovery in tourism and continued strength in the construction and real estate industries, the State of Hawaii Department of Business, Economic Development and Tourism (DBEDT) expects real growth of 2.1% again in 2003. Economic growth is also signaled by the Hawaii index of leading economic indicators (maintained by DBEDT), which has risen nine straight months through October 2002 and indicates improving economic conditions over the next five to ten months. A potential war with Iraq, increasing tensions with North Korea and the threat of major new terroristic events in the U.S. are key uncertainties and risks to Hawaii’s economic growth. Should such global events occur, people may be reluctant to travel and Hawaii’s visitor industry would suffer. Any military troop deployments out of Hawaii will also have a negative economic impact.

Sales

Consolidated sales of electricity were 9,544 million KWHs for 2002, 9,370 million KWHs for 2001, and 9,272 million KWHs for 2000. Despite slightly cooler temperatures, which typically result in lower residential and commercial air conditioning usage, KWH sales increased by 1.9% in 2002 partly due to an increase in the number of residential customers, higher customer KWH usage primarily by residential customers, and a recovery in the local economy following the events of the September 11, 2001 terrorist attacks. KWH sales for the fourth quarter of 2002 increased by 2.9% over the fourth quarter of 2001.

The 1.1% increase in KWH sales in 2001 was primarily due to warmer temperatures, which typically result in higher residential and commercial air conditioning usage, and an increase in the number of customers. Through August 2001, KWH sales were up 1.6%. However, declining tourism and the weakened economy after the September 11, 2001 terrorist attacks caused a 0.4% decrease in KWH sales in the fourth quarter 2001 compared to the fourth quarter 2000.

Operating revenues

The rate schedules of the Company 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 costs, and the relative amounts of company-generated power and purchased power.

Operating revenues were $1,252.9 million in 2002, compared to $1,284.3 million in 2001 and $1,270.6 million in 2000. The 2002 decrease in operating revenues of $31.4 million, or 2.4%, was due to lower energy prices which were passed on to customers ($59.6 million), partially offset by a 1.9% increase in KWH sales ($24.8 million). The 2001 increase in operating revenues of $13.7 million, or 1.1% over 2000, was due to a 1.1% increase in KWH sales ($12.2 million) and a HELCO rate increase ($6.0 million), partially offset by lower energy prices which were passed through to customers ($8.7 million).

Operating expenses

Total operating expenses were $1,117.8 million in 2002 compared to $1,149.0 million in 2001 and $1,137.5 million in 2000. The decrease in 2002 was due to decreased expenses for fuel oil, purchase power and taxes other than income taxes, partially offset by higher other operation, maintenance, and depreciation expenses. The increase in 2001 was due to increases in expenses for purchased power, other operation, depreciation and taxes other than income taxes, partly offset by a decrease in fuel oil and maintenance expenses.

Fuel oil expense was $310.6 million in 2002 compared to $346.7 million in 2001 and $362.9 million in 2000. The 10.4% decrease in 2002 was due primarily to lower fuel oil prices, partly offset by more KWHs generated. The 4.5% decrease in 2001 was due primarily to lower KWHs generated. In 2002, the Company paid an average of $29.10 per barrel for fuel oil, compared to $33.49 in 2001 and $33.44 in 2000.

Purchased power expense was $326.5 million in 2002 compared to $337.8 million in 2001 and $311.2 million in 2000. The decrease in purchased power expense in 2002 was due to lower fuel prices, lower purchased capacity payments to an independent power producer (IPP) who was able to produce only an average of about 5.6 megawatts (MW) of firm capacity since April 2002, compared to the 30 MW the IPP contracted to provide to HELCO, and lower KWHs purchased. The increase in purchased power expense in 2001 was due to higher purchased capacity payments resulting from increased capacity (including a new IPP, Hamakua Partners, in August 2000), higher availability and more KWHs purchased, partially offset by lower energy prices. Purchased

6

KWHs provided approximately 38.0% of the total energy net generated and purchased in 2002 compared to 39.0% in 2001 and 36.4% in 2000.

Other operation expenses totaled $131.9 million in 2002, compared to $125.6 million in 2001 and $123.8 million in 2000. The increase in other operation expenses in 2002 was primarily due to higher employee benefits expense, including $7 million lower retirement benefits income, net of amounts capitalized, primarily due to a 25 basis points lower discount rate and the decline in the market performance of plan assets—i.e., $10 million retirement benefits income in 2002 compared to $17 million in 2001. The increase in other operation expenses in 2001 was primarily due to higher injuries and damages expense, partially offset by lower production operation expenses. HEI charges for general management, administrative and support services totaled $2.2 million in 2002, $2.0 million in 2001 and $1.8 million in 2000.

Maintenance expenses in 2002 of $66.5 million increased by $4.7 million from 2001 due primarily to a larger scope and timing of generating unit overhauls, higher production corrective maintenance and higher transmission and distribution maintenance work. Maintenance expenses in 2001 of $61.8 million decreased by $4.3 million from 2000 due primarily to lower production maintenance expenses largely due to less station maintenance expenses, and less transmission and distribution maintenance work.

Depreciation expense was up 4.7% in 2002 to $105.4 million and up 2.2% in 2001 to $100.7 million. In both years, the increases reflect depreciation on additions to plant in service in the previous year. Major additions to plant in service included HECO’s Archer-Kewalo 138 kilovolt (KV) Line #2, Kewalo-Kamoku 138 KV line and Waiau Water Treatment System in 2001 and HECO’s Archer-Kewalo 138 KV Line #1 and MECO’s 20MW combustion turbine Maalaea Unit 19 in 2000.

Taxes, other than income taxes, decreased by 0.6% in 2002 to $120.1 million and increased by 0.9% in 2001 to $120.9 million. These taxes consist primarily of taxes based on revenues, and the increases in these taxes reflect the corresponding increases in each year’s operating revenues. In 2002, the lower taxes, other than income taxes, resulting from a decrease in operating revenues, were partially offset by a $2 million non-recurring PUC fee adjustment.

Operating income

Operating income for 2002 decreased 0.1% compared to 2001 due to higher other operation, maintenance and depreciation expenses, partially offset by higher KWH sales and lower fuel oil and purchased power expenses. Operating income for 2001 increased 1.6% compared to 2000 due to higher KWH sales and lower maintenance expenses, partially offset by higher other operation and depreciation expenses.

Other income

Other income for 2002 totaled $7.1 million, compared to $7.4 million for 2001 and $9.9 million for 2000. The decreases in 2002 and 2001 were due largely to lower Allowance for Equity Funds Used During Construction (AFUDC-Equity) due to the lower base on which AFUDC-Equity was calculated.

Interest and other charges

Interest and other charges for 2002 totaled $51.0 million, compared to $53.4 million for 2001 and $54.7 million for 2000. Interest and other charges included $7.7 million of preferred securities distributions by HECO’s trust subsidiaries each year in 2002, 2001 and 2000. See Note 3 in the “Notes to Consolidated Financial Statements” for a discussion of the preferred securities issued by the trust subsidiaries.

Interest on long-term debt for 2002 of $40.7 million, compared to $40.3 million for 2001 and $40.1 million for 2000 reflect interest on drawdowns of tax-exempt Special Purpose Revenue Bonds (SPRB) during the year and the full year’s interest on the prior year’s drawdowns of SPRB proceeds, partially offset by lower bond interest rates. In January 2002, HELCO’s $2 million of 7  ⁷/8% Series J First Mortgage Bonds (FMB) and $3 million of 7  ³/4% Series K FMB were redeemed. In November 2000, $21 million of 7.6% Series 1990B SPRB and $45 million of 7  ³/8% Series 1990C SPRB were refinanced using proceeds from the 5.7% Series 2000 SPRB.

Other interest charges were $1.5 million for 2002, compared to $4.7 million for 2001 and $7.0 million for 2000. The decreases in 2002 and 2001 were primarily due to lower short-term borrowings and lower short-term interest rates.

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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. the cost of purchased power) and the cost of plant and equipment, including the cost of new capital projects to maintain and improve service reliability. As of February 12, 2003, the return on average common equity (ROACE) found by the PUC to be reasonable in the most recent final rate decision for each utility was 11.40% for HECO (decision and order (D&O) issued on December 11, 1995, based on a 1995 test year), 11.50% for HELCO (D&O issued on February 8, 2001, based on a 2000 test year) and 10.94% for MECO (amended D&O issued on April 6, 1999, based on a 1999 test year). For 2002, the actual simple average ROACEs (calculated under the rate-making method and reported to the PUC) for HECO, HELCO and MECO were 11.33%, 7.52% and 10.30%, respectively.

Hawaiian Electric Company, Inc. HECO has not initiated a rate case for several years, but in 2001 it committed to initiate a rate case within three years, using a 2003 or 2004 test year, as part of the agreement described below under “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 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.

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 “Certain factors that may affect future results and financial condition–Other regulatory and permitting contingencies” and “HELCO power situation” in Note 11 of the “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 rest of the rate case. The rider provides the rates, terms and conditions for obtaining backup and supplemental electric power from the utility when a customer obtains all or part of its electric power from sources other than HELCO.

Other regulatory matters

Demand-side management programs - lost margins and shareholder incentives. HECO, HELCO and MECO’s energy efficiency demand-side management (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’ forecasted 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.

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Demand-side management programs – agreements with the Consumer Advocate. In October 2001, HECO and the Consumer Advocate finalized agreements, subject to PUC approval, under which HECO’s three commercial and industrial DSM programs and two residential DSM programs would be continued until HECO’s next rate case, which, under the agreements, HECO committed to file using a 2003 or 2004 test year and following the PUC’s rules for determining the test year. The agreements for the temporary continuation of HECO’s existing DSM programs were in lieu of HECO continuing to seek approval of new 5-year DSM programs. Any DSM programs to be in place after HECO’s next rate case will be determined as part of the case. Under the agreements, HECO will cap the recovery of lost margins and shareholder incentives if such recovery would cause HECO to exceed its current authorized return on rate base. HECO also agreed it will not pursue the continuation of lost margins recovery and shareholder incentives through a surcharge mechanism in future rate cases. Consistent with the HECO agreements, in October 2001, HELCO and MECO reached agreements with the Consumer Advocate and filed requests to continue their four existing DSM programs. In November 2001, the PUC issued orders (one of which was later amended) that, subject to certain reporting requirements and other conditions, approved (1) the agreements regarding the temporary continuation of HECO’s five existing DSM programs until HECO’s next rate case and (2) the agreements regarding the temporary continuation of HELCO’s and MECO’s DSM programs until one year after the PUC makes a revenue requirements determination in HECO’s next rate case. Under the orders, however, HELCO and MECO are allowed to recover only lost margins and shareholder incentives accrued through the date that interim rates are established in HECO’s next rate case, but may request to extend the time of such accrual and recovery for up to one additional year. In 2002, MECO’s revenues from shareholder incentives were $0.7 million lower than the amount that would have been recorded if MECO had not agreed to cap such incentives when its authorized return on rate base was exceeded. Also in 2002, HELCO slightly exceeded its authorized return on rate base. If an adjustment is required due to the higher rate of return, HELCO may need to reduce its recorded shareholder incentives by approximately $30,000. In 2002, HECO did not exceed its authorized return on rate base.

Collective bargaining agreements

In August 2000, HECO, HELCO and MECO employees represented by the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260, ratified collective bargaining agreements covering approximately 62% of the employees of HECO, HELCO and MECO. The collective bargaining agreements (including benefit agreements) cover a three-year period from November 1, 2000 through October 31, 2003 and expire at midnight on October 31, 2003. The main provisions of the agreements include noncompounded wage increases of 2.25% effective November 1, 2000, 2.5% effective November 1, 2001 and 2.5% effective November 1, 2002. The agreements also included increased employee contributions to medical premiums. The Company expects to begin negotiations for new collective bargaining agreements in the third quarter of 2003.

Legislation

Congress and the Hawaii legislature periodically consider legislation that could have positive or negative effects on the utilities and their customers. The 2003 Hawaii legislature is considering measures that would undertake a comprehensive audit of Hawaii’s electric utility regulatory policies, energy policies and support for reducing Hawaii’s dependence on imported petroleum for electrical generation. The legislature is also considering a measure to remove the cap for net energy metering. Management cannot predict whether these proposals will be enacted into law.

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

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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).

HECO and its subsidiaries currently support renewable sources in various ways, including their solar water heating and heat pump programs and their purchased power contracts with nonutility generators using renewable sources (e.g., refuse-fired, geothermal, hydroelectric and wind turbine generating systems). HECO and its subsidiaries continue to initiate and support many renewable energy research and development projects to help develop these technologies (e.g., photovoltaic projects). They are also conducting integrated resource planning to evaluate the use of more renewables and, in December 2002, HECO formed a subsidiary, Renewable Hawaii, Inc., to invest in renewable energy projects. About 6.8% of electricity sales for 2002 were from renewable resources (as defined under the renewable portfolio standard law). Despite its efforts, HECO and its subsidiaries believe it may be difficult to increase this percentage to the percentages targeted in the 2001 Hawaii legislation, particularly if sales of electricity increase in future years as projected. Thus, at this time, management cannot predict the impact of this law or of other proposed congressional and Hawaii legislation on the utilities or their customers.

Effects of inflation

U.S. inflation, as measured by the U.S. Consumer Price Index, averaged an estimated 1.6% in 2002, 2.8% in 2001 and 3.4% in 2000. Hawaii inflation, as measured by the Honolulu Consumer Price Index, averaged an estimated 1.2% in 2002, 1.2% in 2001 and 1.7% in 2000. Although the rate of inflation over the past several years has been relatively 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” in Note 1 of the “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 construction programs and to cover debt and other cash requirements in the foreseeable future.

The Company’s total assets were $2.4 billion at December 31, 2002 and 2001.

The consolidated capital structure of the Company was as follows:

December 31	2002				2001
(in millions)
Short-term borrowings from affiliate	$	6	—	%	$	49	3	%
Long-term debt including amounts due within one year		705	40			685	39
HECO-obligated preferred securities of trust subsidiaries		100	6			100	6
Preferred stock		34	2			34	2
Common stock equity		923	52			877	50
	$	1,768	100	%	$	1,745	100	%

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As of February 12, 2003, 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 (insured)	AAA	Aaa
Revenue bonds (noninsured)	BBB+	Baa1
HECO-obligated preferred securities of trust subsidiaries	BBB-	Baa2
Cumulative preferred stock (selected series)	NR	Baa3

NR Not rated.

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

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

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

From time to time, HECO utilizes short-term debt, principally commercial paper, to support normal operations and for other temporary requirements. HECO also borrows short-term from HEI from time to time. HECO had average outstanding balances of commercial paper for 2002 of $9.6 million. HECO had no commercial paper outstanding at December 31, 2002. Management believes that, if HECO’s commercial paper ratings were to be downgraded, HECO might not be able to sell commercial paper under current market conditions.

At December 31, 2002, HECO maintained bank lines of credit totaling $100 million (all maturing in 2003). On January 1, 2003, HECO reduced its total lines of credit to $90 million. These lines of credit are principally maintained by HECO to support the issuance of commercial paper and 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 was to reduce or eliminate access to the commercial paper markets. 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, 2002, 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 the “Notes to Consolidated Financial Statements.”

Capital expenditures requiring the use of cash, as shown on the “Consolidated Statements of Cash Flows,” totaled approximately $114.6 million in 2002, of which $71.3 million was attributable to HECO, $27.6 million to HELCO and $15.7 million to MECO. Approximately 64% of the total 2002 capital expenditures were for transmission and distribution projects and approximately 36% was for generation and general plant projects. Cash contributions in aid of construction received in 2002 totaled $11.0 million.

In 2002, the Company’s investing activities used $103.5 million in cash, primarily for capital expenditures. Financing activities used net cash of $68.2 million, including $52.9 million for the payment of common and preferred stock dividends and trust preferred securities distributions, $42.7 million for the net repayment of short-term borrowings, partly offset by a $30.3 million net increase in long-term debt. Operating activities provided cash of $171.6 million.

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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 in the principal amount of $40 million with a maturity of 30 years and a fixed coupon rate of 5.10% (yield of 5.15%), and loaned the proceeds from the sale to HECO. Payments on the revenue bonds are insured by a financial guaranty policy issued by Ambac Assurance Corporation.

As of December 31, 2002, $16.1 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. Also as of December 31, 2002, an additional $25 million of special purpose revenue bonds were authorized by the Hawaii Legislature for issuance by the Department of Budget and Finance of the State of Hawaii for the benefit of HELCO prior to the end of 2003.

As further explained in Note 10 in the “Notes to Consolidated Financial Statements,” the Company participates in 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 is not required to make any contributions to the pension plans to meet minimum funding requirements pursuant to ERISA for 2003, but the HEI Pension Investment Committee (PIC) may choose to make contributions to the pension plans in 2003. 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 HEI PIC reserves the right to change, modify or terminate the pension plans, and the Company reserves the right to change, modify or terminate its postretirement benefit plan. From time to time in the past, benefits have changed. Due to the sharp declines in U.S. equity markets beginning in 2000, the value of a significant portion of the assets held in the plans’ trusts to satisfy the obligations of the pension and other postretirement plans has decreased significantly. As a result, 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. The Company’s consolidated financing requirements for 2003 through 2007, including net capital expenditures and long-term debt repayments, are estimated to total $0.7 billion. Consolidated internal sources (primarily consolidated cash flows from operations comprised mainly of net income, adjusted for noncash income and expense items such as depreciation, amortization and deferred taxes, and changes in working capital), after the payment of common stock and preferred stock dividends, are expected to provide cash in excess of the consolidated financing requirements and may be used to reduce the level of borrowings. HECO does not anticipate the need to issue common equity over the five-year period 2003 through 2007. Debt and/or equity financing may be required, however, to fund unanticipated expenditures not included in the 2003 through 2007 forecast, such as increases in the costs of or an acceleration of the construction of capital projects, unbudgeted acquisitions or investments in new businesses and significant increases in retirement benefit funding requirements that might be required if there were significant declines in the market value of pension plan assets or changes in actuarial assumptions. The PUC must approve issuances, if any, of equity and long-term debt securities by HECO, HELCO and MECO.

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

For 2003, net capital expenditures are estimated to be $158 million. Gross capital expenditures are estimated to be $183 million, including approximately $103 million for transmission and distribution projects, approximately $58 million for generation projects and approximately $22 million for general plant and other projects. Drawdowns of the remaining $16.1 million of proceeds from the Series 2002A sale of tax-exempt special purpose revenue bonds and the generation of funds from internal sources are expected to provide the cash needed for the net capital expenditures in 2003.

Management periodically reviews capital expenditure estimates and the timing of construction projects. These estimates may change significantly as a result of many considerations, including changes in economic conditions, changes in forecasts of KWH sales and peak load, the availability of purchased power and changes in expectations concerning the construction and ownership of future generating units, the availability of generating sites and transmission and distribution corridors, the ability to obtain adequate and timely rate increases,

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escalation in construction costs, the impacts of DSM programs, the effects of opposition to proposed construction projects and requirements of environmental and other regulatory and permitting authorities.

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

Selected contractual obligations

The following tables present aggregated information about certain contractual obligations and commercial commitments:

December 31, 2002	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	$	—	$	—	$	—	$	726	$	726
HECO-obligated preferred securities of trust subsidiaries		—		—		—		100		100
Operating leases		2		3		1		2		8
Fuel oil purchase obligations (estimate based on January 1, 2003 fuel oil prices)		329		330		—		—		659
Purchase power obligations – minimum fixed capacity charges		123		241		236		1,607		2,207
	$	454	$	574	$	237	$	2,435	$	3,700

The tables above do not include other categories of obligations and commitments, such as 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.

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 it provides 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 in Hawaii has become increasingly competitive. IPPs are well established in Hawaii and continue to actively pursue new projects. Competition in the generation sector in Hawaii is moderated, however, by the scarcity of generation sites, various permitting processes and lack of interconnections to other electric utilities. Customer self-generation, with or without cogeneration, is a continuing competitive factor. Historically, HECO and its subsidiaries have been able to compete by offering customers economic alternatives that, among other things, employ energy efficient electrotechnologies such as the heat pump water heater. However, the number of customer self-generation projects that are being proposed or installed in Hawaii, particularly those involving combined heat and power (CHP) systems, is growing. CHP systems are a form of distributed generation (DG), and produce electricity and thermal energy from gas, propane or diesel-fired engines. In Hawaii, the thermal energy generally is used to heat water and, through an absorption chiller, drive an air conditioning system. The electric energy generated by these systems is usually lower in output than the customer’s load, which results in continued connection to the utility grid to make up the difference in electricity demand and to provide back up electricity.

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The Company has initiated several demonstration projects and other activities, including a small customer-owned CHP demonstration project on Maui, to provide on-going evaluation of DG. The Company also has made a limited number of proposals to customers, which are subject to PUC approval, to install and operate utility-owned CHP systems at the customers’ sites. The Company is in the planning stage to expand its offering of CHP systems to its commercial customers as part of its regulated electric utility service. 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. The offering of CHP systems would be subject to PUC review and approval. To facilitate such an offering, 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 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 states 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.” HECO is unable to predict the ultimate outcome of the proceeding, which of the proposals (if any) advanced in the proceeding will be implemented or whether the parties will seek and obtain state legislative action on their proposals (other than the legislation described above under “Results of operations–Legislation”).

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 retirement benefits expense, net of amounts capitalized and income taxes, will be $8 million in 2003 as compared to net retirement benefits income of $6 million in 2002 (or $14 million less net income), partly as a result of the effect of the stock market decline on the performance of the assets in HEI’s master pension trust.

HECO and its subsidiaries are exposed to interest rate risk primarily due to their borrowings. They attempt to manage this risk in part by incurring or refinancing debt in periods of low interest rates and by usually issuing fixed-rate rather than floating-rate long-term debt. As of December 31, 2002, the Company had no commercial paper outstanding.

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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

The Company is 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 utility 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. HECO, HELCO and MECO 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.

An ongoing environmental investigation is the Honolulu Harbor environmental investigation described in Note 11 in the “Notes to Consolidated Financial Statements.” 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.

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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, 2002, HECO and its subsidiaries had recognized $16 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 using a 2003 or 2004 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 Company’s 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. HECO and its electric utility subsidiaries believe that the energy cost adjustment clauses continue to be necessary. These clauses were continued in the most recent HELCO and MECO rate cases (final D&O’s issued in February 2001 and April 1999, respectively).

Consultants periodically conduct depreciation studies for the 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 negatively impacted by the depreciation rates and method ultimately approved by the PUC.

Fuel oil and purchased power

HECO and its electric utility subsidiaries rely on fuel oil suppliers and independent power producers to deliver fuel oil and power, respectively. The Company estimates that 77% of the net energy generated and purchased in 2003 will be generated from the burning of oil. Purchased KWHs provided approximately 38.0% of the total net energy generated and purchased in 2002 compared to 39.0% in 2001 and 36.4% in 2000.

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, Australia 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.

16

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. The following two major capital improvement projects, the Keahole project and the Kamoku-Pukele transmission line, have encountered opposition and the Keahole project has been seriously delayed.

Keahole project. In 1991, HELCO began planning to meet increased electric generation demand forecasted for 1994. HELCO’s plans were to install at its Keahole power plant two 20 MW combustion turbines (CT-4 and CT-5), followed by an 18 MW heat steam recovery generator, at which time these units would be converted to a 56 MW (net) dual-train combined-cycle unit. The timing of the installation of HELCO’s phased units has been revised on several occasions due to delays in obtaining an air permit and a land use permit amendment, in addition to delays caused by the commencement of lawsuits and administrative proceedings, many of which are on appeal or otherwise have not been finally resolved. See Note 11 in the “Notes to Consolidated Financial Statements” for a more detailed description of the history and status of this project.

In September 2000, the Third Circuit Court of the State of Hawaii (Circuit Court) ruled that, absent a legal or equitable extension properly authorized by the Board of Land and Natural Resources (BLNR), HELCO’s further construction of CT-4 and CT-5 could not proceed because HELCO had not completed construction within the three-year construction period the Circuit Court found to be applicable to the project, unless the BLNR extended the construction period. HELCO subsequently obtained a BLNR order extending the construction period, but the Circuit Court then ruled, on September 19, 2002, that the BLNR did not have authority to grant the extension. As a result of this ruling, the construction of CT-4 and CT-5 has been suspended.

HELCO has appealed to the Hawaii Supreme Court both the Circuit Court 2000 ruling that there was a three-year construction period that had expired and the Circuit Court’s later ruling that BLNR could not extend the construction period. HELCO also filed motions to expedite the appeal and to stay the Circuit Court’s ruling pending the appeal. The Hawaii Supreme Court has denied the motion to expedite the appeal and the motion to stay the Circuit Court’s ruling pending appeal. In early 2003, the Hawaii Supreme Court also ruled that the appeal from the Circuit Court’s ruling in 2000 that the construction period had expired was not timely (even though the Circuit Court ruled at the time that its Order could not yet be appealed) and dismissed the appeal. HELCO cannot predict when its appeal of the Circuit Court’s ruling that the BLNR lacked authority to extend the construction deadline will be decided.

HELCO continues to consider other options that may allow HELCO to complete the installation of CT-4 and CT-5 (including seeking a land use reclassification of the Keahole site from the State Land Use Commission). If none of these options is ultimately successful and HELCO does not prevail on its appeal, HELCO may be unable to complete the installation of CT-4 and CT-5. The recovery of costs relating to CT-4 and CT-5 are subject to the rate-making process governed by the PUC. Management believes no adjustment to costs incurred to put CT-4 and CT-5 into service is required as of December 31, 2002. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HELCO may be required to write off a material portion of the costs incurred in its efforts to put these units into service whether or not CT-4 and CT-5 are installed. As of December 31, 2002, HELCO’s costs incurred in its efforts to put CT-4 and CT-5 into service and to support existing units (excluding costs the PUC permitted to be transferred to plant-in-service for pre-air permit facilities in HELCO’s most recent rate case) amounted to approximately $82 million, including $32 million for equipment and material purchases, $30 million for planning, engineering, permitting, site development and other costs and $20 million for AFUDC charged to the project prior to HELCO’s decision to discontinue the further accrual of AFUDC on CT-4 and CT-5. HELCO discontinued the accrual of AFUDC effective December 1, 1998, due in part to the delays and the potential for further delays. In addition to the $82 million in construction in progress, construction and/or purchase commitments related to CT-4 and CT-5 outstanding as of December 31, 2002 are estimated at approximately $0.6 million. See “HELCO Power Situation” in Note 11 of the “Notes to Consolidated Financial Statements.”

17

Kamoku-Pukele transmission line. HECO has for some time been expending efforts to address future potential line overloads in its two major corridors (Northern and Southern) transmitting bulk power to the Honolulu/East Oahu area, and to improve the reliability of the Pukele substation at the end of the Northern corridor. HECO planned to construct a part underground/part overhead 138 kv transmission line from the Kamoku substation to the Pukele substation in order to close the gap between the Southern and Northern transmission corridors and provide a third 138 kv transmission line to the Pukele substation. Construction of the Kamoku to Pukele transmission line in its proposed location required the BLNR to approve a Conservation District Use Permit (CDUP) for the overhead portion of the line that would have been in conservation district lands. On June 28, 2002, the BLNR issued a ruling denying HECO’s request for the CDUP.

HECO continues to believe that the proposed project is needed. HECO is evaluating alternative ways to accomplish the project, and possible future actions to expedite PUC review of the alternatives and the need for the project. As of December 31, 2002, the accumulated costs related to the Kamoku to Pukele transmission line amounted to $17 million, including $12 million for planning, engineering and permitting costs and $5 million for AFUDC. These costs are recorded in construction in progress. The recovery of costs relating to the Kamoku to Pukele transmission line project is subject to the rate-making process governed by the PUC. Management believes no adjustment to costs incurred to put the Kamoku to Pukele transmission line into service is required as of December 31, 2002. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HECO may be required to write off a material portion or all of the costs incurred in its efforts to put the Kamoku to Pukele transmission line into service whether or not the line is installed. See “Oahu transmission system” in Note 11 of the “Notes to Consolidated Financial Statements.”

Material estimates and critical accounting policies

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

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

In accordance with SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” management has identified the 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.

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

Utility plant

Utility plant is reported at cost. Self-constructed electric 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 or sale of electric utility plant, no gain or loss is recognized. The cost of the plant retired or sold and the cost of removal (net of salvage value) previously provided through depreciation are charged to accumulated depreciation.

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 above concerning costs recorded in construction in progress for CT-4 and CT-5 at Keahole and the proposed Kamoku-Pukele transmission line under “Certain factors that may affect future results and financial condition-Other regulatory and permitting contingencies.”

18

Pension and other postretirement benefits

Pension and other postretirement benefit costs/(returns) are charged/(credited) primarily to expense and electric utility plant.

The Company’s reported costs of providing retirement benefits (described in Note 10 in the “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 2002, 2001 and 2000 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 2002 and 2001, the Company recorded other postretirement benefit expense, net of amounts capitalized, of approximately $4 million and $2 million, respectively, in accordance with the provisions of SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” Actual payments of benefits made to retirees during 2002 and 2001 were $6 million and $7 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 2002 and 2001, the Company recorded non-cash pension income, net of amounts capitalized, of approximately $14 million and $19 million, respectively, and paid benefits of $34 million and $32 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 HEI PIC considers the Moody’s Aa and Aaa Daily Long-Term Corporate Bond Yield Averages, as well as yields for 20 and 30 year Treasury strips. In selecting an assumed rate of return on plan assets, the HEI PIC 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 the “Notes to Consolidated Financial Statements,” the HEI PIC has revised key assumptions at December 31, 2002 compared to December 31, 2001. Such changes will not have an impact on reported costs in 2002; however, for future years, such changes will have a significant impact. Based upon the 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), the Company estimates that retirement benefits expense, net of amounts capitalized and income taxes, will be $8 million in 2003 as compared to net retirement benefits income of $6 million in 2002 (or $14 million less net income). In determining the retirement benefit costs, these 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 associated with a change in certain actuarial assumptions by the indicated percentage and constitute “forward-looking statements.” While the tables below reflect an increase or decrease in the percentage for each assumption, the HEI PIC and its actuaries expect that the inverse of these changes would impact the projected benefit obligation (PBO) and 2003 net income in the opposite direction. 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 postretirement benefits plan.

19

Actuarial assumption	Change in assumption		Impact on PBO		Impact on 2003 net income
(in millions)
Pension benefits
Discount rate	(0.5	)%	$	46.0	$	(1.9	)
Rate of return on plan assets	(0.5	)		—		(1.2	)
Other benefits
Discount rate	(0.5	)		9.1		(0.1	)
Health care cost trend rate	0.5			1.9		(0.1	)
Rate of return on plan assets	(0.5	)		—		(0.2	)

Environmental expenditures

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. Liabilities are recorded when environmental assessments and/or remedial efforts are probable, and the cost can be reasonably estimated. Estimated costs are based upon an expected level of contamination and remediation efforts. Should the level of contamination and remediation efforts be different than initially expected, the ultimate costs will differ. See “Environmental regulation” in Note 11 of the “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.

Governmental tax authorities could challenge a tax return position taken by management, and such challenges might not be raised and finally resolved until several years after the events in question. If the Company’s position does not prevail, the Company’s results of operations and financial condition may be adversely affected as the related deferred or current income tax asset would be impaired.

20

Regulation by the PUC

HECO, HELCO and MECO are regulated by the PUC. In accordance with Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” the Company’s financial statements reflect assets 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. As of December 31, 2002, regulatory assets amounted to $106 million. These regulatory assets are itemized in Note 6 of the “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 existing regulatory assets and rates in effect allow the utilities to earn a reasonable rate of return, management believes the existing regulatory assets 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 HECO and its electric utility subsidiaries’ operations currently satisfy the SFAS No. 71 criteria. However, if events or circumstances should change so that those criteria are no longer satisfied, management believes that a material adverse effect on the Company’s results of operations and financial position may result as regulatory assets would be charged to expense.

Electric utility revenues

Electric utility 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, 2002, 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, 2002, HECO and its electric utility subsidiaries had recognized $16 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. 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 $1.9 million (before interest) of the $8.5 million of integrated resource planning costs incurred from 1995 through 1998 and in 2001, and the PUC’s decision is pending on this matter. The Consumer Advocate has not stated its position on the recovery of the $1.5 million of integrated resource planning costs incurred from 1999 through 2000.

The rate schedules of HECO and its electric utility subsidiaries 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 HECO and its electric utility subsidiaries’ 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. HECO and its electric utility subsidiaries believe that the energy cost adjustment clauses continue to be necessary. These clauses were continued in the most recent HELCO and MECO rate cases.

21

Quantitative and Qualitative Disclosures about Market Risk

The Company manages various market risks in the ordinary course of business, including credit risk and liquidity risk, and believes its exposures to these risks are not material as of December 31, 2002. Because the Company does not have a portfolio of trading assets, the Company is not exposed to market risk from trading activities.

The Company is exposed to some commodity price risk primarily related to its fuel supply and IPP contracts, which is mitigated by the energy cost adjustment clauses in the Company’s rate schedules.

The Company considers interest rate risk to be a significant market risk as it could potentially have a significant effect on the Company’s results of operations and financial condition. Interest rate risk can be defined as the exposure of the Company’s earnings to adverse movements in interest rates. The Company does not currently use derivatives to manage interest rate risk. The Company’s general policy is to manage interest rate risk through use of a combination of short- and long-term debt (primarily fixed-rate debt) and preferred securities.

The tables below provide information about the Company’s market sensitive financial instruments in U.S. dollars, including contractual balances at the stated maturity dates as well as the estimated fair values as of December 31, 2002 and 2001, and constitute “forward-looking statements.”

See Note 15 in the “Notes to Consolidated Financial Statements” for descriptions of the methods and assumptions used to estimate fair value of each applicable class of financial instruments.

December 31, 2002	Expected maturity
(dollars in millions)	2003			2004	2005	2006	2007	Thereafter			Total			Estimated fair value
Interest-sensitive liabilities
Short-term borrowings	$	6		—	—	—	—		—		$	6		$	6
Average interest rate		1.5	%	—	—	—	—		—			1.5	%
Long-term debt- fixed rate		—		—	—	—	—	$	705		$	705		$	736
Average interest rate		—		—	—	—	—		5.8	%		5.8	%
HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts		—		—	—	—	—	$	100		$	100		$	100
Average distribution rate		—		—	—	—	—		7.7	%		7.7	%
December 31, 2001	Expected maturity
(dollars in millions)	2002			2003	2004	2005	2006	Thereafter			Total			Estimated fair value
Interest-sensitive liabilities
Short-term borrowings	$	48		—	—	—	—		—		$	48		$	48
Average interest rate		2.0	%	—	—	—	—		—			2.0	%
Long-term debt- fixed rate	$	15		—	—	—	—	$	670		$	685		$	666
Average interest rate		7.9	%	—	—	—	—		5.9	%		5.9	%
HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts		—		—	—	—	—	$	100		$	100		$	100
Average distribution rate		—		—	—	—	—		7.7	%		7.7	%

22

Independent Auditors’ Report

To the Board of Directors and Stockholder

Hawaiian Electric Company, Inc.:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Hawaiian Electric Company, Inc. (a wholly-owned subsidiary of Hawaiian Electric Industries, Inc.) and subsidiaries as of December 31, 2002 and 2001, 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, 2002. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Hawaiian Electric Company, Inc. and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

Honolulu, Hawaii

January 20, 2003

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Consolidated Statements of Income

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31,	2002			2001			2000
(in thousands)
Operating revenues	$	1,252,929		$	1,284,312		$	1,270,635
Operating expenses:
Fuel oil		310,595			346,728			362,905
Purchased power		326,455			337,844			311,207
Other operation		131,910			125,565			123,779
Maintenance		66,541			61,801			66,069
Depreciation		105,424			100,714			98,517
Taxes, other than income taxes		120,118			120,894			119,784
Income taxes		56,729			55,434			55,213
		1,117,772			1,148,980			1,137,474
Operating income		135,157			135,332			133,161
Other income:
Allowance for equity funds used during construction		3,954			4,239			5,380
Other, net		3,141			3,197			4,555
		7,095			7,436			9,935
Income before interest and other charges		142,252			142,768			143,096
Interest and other charges:
Interest on long-term debt		40,720			40,296			40,134
Amortization of net bond premium and expense		2,014			2,063			1,938
Other interest charges		1,498			4,697			6,990
Allowance for borrowed funds used during construction		(1,855	)		(2,258	)		(2,922	)
Preferred stock dividends of subsidiaries		915			915			915
Preferred securities distributions of trust subsidiaries		7,675			7,675			7,675
		50,967			53,388			54,730
Income before preferred stock dividends of HECO		91,285			89,380			88,366
Preferred stock dividends of HECO		1,080			1,080			1,080
Net income for common stock	$	90,205		$	88,300		$	87,286

Consolidated Statements of Retained Earnings

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31,	2002			2001			2000
(in thousands)
Retained earnings, January 1	$	495,961		$	443,970		$	425,206
Net income for common stock		90,205			88,300			87,286
Common stock dividends		(44,143	)		(36,309	)		(68,522	)
Retained earnings, December 31	$	542,023		$	495,961		$	443,970

See accompanying “Notes to Consolidated Financial Statements.”

24

Consolidated Balance Sheets

Hawaiian Electric Company, Inc. and Subsidiaries

December 31,	2002			2001
(in thousands)
Assets
Utility plant, at cost:
Land	$	31,896		$	31,689
Plant and equipment		3,184,818			3,068,254
Less accumulated depreciation		(1,367,954	)		(1,266,332	)
Plant acquisition adjustment, net		302			354
Construction in progress		164,300			170,558
Net utility plant		2,013,362			2,004,523
Current assets:
Cash and equivalents		1,726			1,858
Customer accounts receivable, net		87,113			81,872
Accrued unbilled revenues, net		60,098			52,623
Other accounts receivable, net		2,213			2,652
Fuel oil stock, at average cost		35,649			24,440
Materials and supplies, at average cost		19,450			19,702
Prepayments and other		75,610			53,744
Total current assets		281,859			236,891
Other assets:
Regulatory assets		105,568			111,376
Unamortized debt expense		13,354			12,443
Long-term receivables and other		22,243			24,505
Total other assets		141,165			148,324
	$	2,436,386		$	2,389,738
Capitalization and liabilities
Capitalization (see Consolidated Statements of Capitalization):
Common stock equity	$	923,256		$	877,154
Cumulative preferred stock, not subject to mandatory redemption		34,293			34,293
HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO and HECO-guaranteed debentures		100,000			100,000
Long-term debt, net		705,270			670,674
Total capitalization		1,762,819			1,682,121
Current liabilities:
Long-term debt due within one year		—			14,595
Short-term borrowings-affiliate		5,600			48,297
Accounts payable		59,992			53,966
Interest and preferred dividends payable		11,532			11,765
Taxes accrued		79,133			86,058
Other		28,020			29,799
Total current liabilities		184,277			244,480
Deferred credits and other liabilities:
Deferred income taxes		158,367			145,608
Unamortized tax credits		47,985			48,512
Other		64,844			55,460
Total deferred credits and other liabilities		271,196			249,580
Contributions in aid of construction		218,094			213,557
	$	2,436,386		$	2,389,738

See accompanying “Notes to Consolidated Financial Statements.”

25

Consolidated Statements of Capitalization

Hawaiian Electric Company, Inc. and Subsidiaries

December 31,	2002		2001		2000
(dollars in thousands, except per share amounts)
Common stock equity:
Common stock of $6  2/3 par value Authorized: 50,000,000 shares Outstanding: 2002, 2001 and 2000, 12,805,843 shares	$	85,387	$	85,387	$	85,387
Premium on capital stock		295,846		295,806		295,655
Retained earnings		542,023		495,961		443,970
Common stock equity		923,256		877,154		825,012
Cumulative preferred stock not subject to mandatory redemption:
Authorized: 5,000,000 shares of $20 par value and 7,000,000 shares of $100 par value. Outstanding: 2002 and 2001, 1,234,657 shares.

Series	Par Value			Shares Outstanding December 31, 2002	2002		2001
(dollars in thousands, except per share amounts)
C-4 1/4%	$	20	(HECO)	150,000		3,000		3,000
D-5%		20	(HECO)	50,000		1,000		1,000
E-5%		20	(HECO)	150,000		3,000		3,000
H-5 1/4%		20	(HECO)	250,000		5,000		5,000
I-5%		20	(HECO)	89,657		1,793		1,793
J-4 3/4%		20	(HECO)	250,000		5,000		5,000
K-4.65%		20	(HECO)	175,000		3,500		3,500
G-7 5/8%		100	(HELCO)	70,000		7,000		7,000
H-7 5/8%		100	(MECO)	50,000		5,000		5,000
				1,234,657	$	34,293	$	34,293

(continued)

See accompanying “Notes to Consolidated Financial Statements.”

26

Consolidated Statements of Capitalization, continued

Hawaiian Electric Company, Inc. and Subsidiaries

December 31,	2002		2001
(in thousands)
HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO and HECO-guaranteed debentures (distribution rates of 7.30% and 8.05%)	$	100,000	$	100,000
Long-term debt:
First mortgage bonds:
HELCO, 7 3/4-7 7/8%, paid in 2002		—		5,000
Obligations to the State of Hawaii for the repayment of Special Purpose Revenue Bonds:
HECO, 5.10%, series 2002A, due 2032		40,000		—
HECO, 5.70%, refunding series 2000, due 2020		46,000		46,000
MECO, 5.70%, refunding series 2000, due 2020		20,000		20,000
HECO, 6.15%, refunding series 1999D, due 2020		16,000		16,000
HELCO, 6.15%, refunding series 1999D, due 2020		3,000		3,000
MECO, 6.15%, refunding series 1999D, due 2020		1,000		1,000
HECO, 6.20%, series 1999C, due 2029		35,000		35,000
HECO, 5.75%, refunding series 1999B, due 2018		30,000		30,000
HELCO, 5.75% refunding series 1999B, due 2018		11,000		11,000
MECO, 5.75%, refunding series 1999B, due 2018		9,000		9,000
HELCO, 5.50%, refunding series 1999A, due 2014		11,400		11,400
HECO, 4.95%, refunding series 1998A, due 2012		42,580		42,580
HELCO, 4.95%, refunding series 1998A, due 2012		7,200		7,200
MECO, 4.95%, refunding series 1998A, due 2012		7,720		7,720
HECO, 5.65%, series 1997A, due 2027		50,000		50,000
HELCO, 5.65%, series 1997A, due 2027		30,000		30,000
MECO, 5.65%, series 1997A, due 2027		20,000		20,000
HECO, 5 7/8%, series 1996B, due 2026		14,000		14,000
HELCO, 5 7/8%, series 1996B, due 2026		1,000		1,000
MECO, 5 7/8%, series 1996B, due 2026		35,000		35,000
HECO, 6.20%, series 1996A, due 2026		48,000		48,000
HELCO, 6.20%, series 1996A, due 2026		7,000		7,000
MECO, 6.20%, series 1996A, due 2026		20,000		20,000
HECO, 6.60%, series 1995A, due 2025		40,000		40,000
HELCO, 6.60%, series 1995A, due 2025		5,000		5,000
MECO, 6.60%, series 1995A, due 2025		2,000		2,000
HECO, 5.45%, series 1993, due 2023		50,000		50,000
HELCO, 5.45%, series 1993, due 2023		20,000		20,000
MECO, 5.45%, series 1993, due 2023		30,000		30,000
HECO, 6.55%, series 1992, due 2022		40,000		40,000
HELCO, 6.55%, series 1992, due 2022		12,000		12,000
MECO, 6.55%, series 1992, due 2022		8,000		8,000
HELCO, 7 3/8%, series 1990C, due 2020		10,000		10,000
HELCO, 7.60%, series 1990B, due 2020		4,000		4,000
		725,900		685,900
Less funds on deposit with trustees		16,111		10,808
Total obligations to the State of Hawaii		709,789		675,092
Other long-term debt – unsecured:
HECO, 7.9% note, paid in 2002		—		9,595
Total long-term debt		709,789		689,687
Less unamortized discount		4,519		4,418
Less amounts due within one year		—		14,595
Long-term debt, net		705,270		670,674
Total capitalization	$	1,762,819	$	1,682,121

See accompanying “Notes to Consolidated Financial Statements.”

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Consolidated Statements of Cash Flows

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31,	2002			2001			2000
(in thousands)
Cash flows from operating activities:
Income before preferred stock dividends of HECO	$	91,285		$	89,380		$	88,366
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Depreciation of utility plant		105,424			100,714			98,517
Other amortization		11,376			12,740			8,808
Deferred income taxes		12,818			8,557			5,961
Tax credits, net		1,031			2,476			982
Allowance for equity funds used during construction		(3,954	)		(4,239	)		(5,380	)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable		(4,802	)		9,448			(23,032	)
Decrease (increase) in accrued unbilled revenues		(7,475	)		11,397			(10,190	)
Decrease (increase) in fuel oil stock		(11,209	)		12,684			(2,170	)
Decrease (increase) in materials and supplies		252			(2,915	)		3,259
Increase in regulatory assets, net		(1,881	)		(4,036	)		(5,748	)
Increase (decrease) in accounts payable		6,026			(17,732	)		19,582
Increase (decrease) in taxes accrued		(6,925	)		7,872			11,651
Other		(20,389	)		(27,597	)		(21,160	)
Net cash provided by operating activities		171,577			198,749			169,446
Cash flows from investing activities:
Capital expenditures		(114,558	)		(115,540	)		(130,089	)
Contributions in aid of construction		11,042			10,958			8,484
Proceeds from sales of assets		56			—			—
Payments on notes receivable		—			—			138
Net cash used in investing activities		(103,460	)		(104,582	)		(121,467	)
Cash flows from financing activities:
Common stock dividends		(44,143	)		(36,309	)		(68,522	)
Preferred stock dividends		(1,080	)		(1,080	)		(1,080	)
Preferred securities distributions of trust subsidiaries		(7,675	)		(7,675	)		(7,675	)
Proceeds from issuance of long-term debt		35,275			17,336			87,507
Repayment of long-term debt		(5,000	)		—			(66,000	)
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		(42,697	)		(61,869	)		3,153
Proceeds from other short-term borrowings		—			—			57,499
Repayment of other short-term borrowings		—			(3,000	)		(55,682	)
Other		(2,929	)		(1,246	)		2,389
Net cash used in financing activities		(68,249	)		(93,843	)		(48,411	)
Net increase (decrease) in cash and equivalents		(132	)		324			(432	)
Cash and equivalents, January 1		1,858			1,534			1,966
Cash and equivalents, December 31	$	1,726		$	1,858		$	1,534

See accompanying “Notes to Consolidated Financial Statements.”

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Notes to Consolidated Financial Statements

Hawaiian Electric Company, Inc. and Subsidiaries

1. Summary of significant accounting policies

General

Hawaiian Electric Company, Inc. (HECO) is engaged in the business of generating, purchasing, transmitting, distributing and selling electric energy on the island of Oahu and, through its two electric utility subsidiaries, Hawaii Electric Light Company, Inc. (HELCO) on the island of Hawaii, and Maui Electric Company, Limited (MECO) on the islands of Maui, Lanai and Molokai in the State of Hawaii. At the end of 2002, HECO formed Renewable Hawaii, Inc., which is expected to invest in renewable energy projects.

Basis of presentation

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

Material estimates that are particularly susceptible to significant change include the amounts reported for regulatory assets, pension and other postretirement benefit obligations, current and deferred taxes, contingencies and litigation.

Consolidation

The consolidated financial statements include the accounts of Hawaiian Electric Company, Inc. (HECO) and its subsidiaries (collectively, the Company). The Company is a wholly-owned subsidiary of Hawaiian Electric Industries, Inc. (HEI). All significant intercompany accounts and transactions have been eliminated in consolidation.

Regulation by the Public Utilities Commission of the State of Hawaii (PUC)

HECO, HELCO and MECO are regulated by the PUC and account for the effects of regulation under Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.” As a result, the actions of regulators can affect the timing of recognition of revenues, expenses, assets and liabilities. Management believes HECO and its subsidiaries’ operations currently satisfy the SFAS No. 71 criteria. However, if events or circumstances should change so that those criteria are no longer satisfied, management believes that a material adverse effect on the Company’s financial statements may result as regulatory assets would be charged to expense.

Utility plant

Utility plant is reported at cost. Self-constructed 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 or sale of electric utility plant, no gain or loss is recognized. The cost of the plant retired or sold and the cost of removal (net of salvage value) previously provided through depreciation are charged to accumulated depreciation.

Depreciation

Depreciation is computed primarily using the straight-line method over the estimated useful lives of the assets being depreciated. Electric utility plant has useful lives ranging from 20 to 45 years for production plant, from 25 to 50 years for transmission and distribution plant and from 8 to 45 years for general plant. The composite annual depreciation rate was 3.9% in 2002, 2001 and 2000.

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Cash and equivalents

The Company considers cash on hand, deposits in banks, money market accounts, certificates of deposit, short-term commercial paper and liquid investments (with original maturities of three months or less) to be cash and equivalents.

Accounts receivable

Accounts receivable are recorded at the invoiced amount. The Company assesses a late payment charge on balances unpaid from the previous month. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts receivable. The Company adjusts its allowance on a monthly basis, based on its historical write-off experience. Account balances are charged off against the allowance after collection efforts have been exhausted and the potential for recovery is considered remote.

Retirement benefits

Pension and other postretirement benefit costs/(returns) are charged/(credited) primarily to expense and electric utility plant. The Company’s policy is to fund pension costs in amounts consistent with the requirements of the Employee Retirement Income Security Act of 1974. Certain health care and/or life insurance benefits are provided to eligible retired employees and the employees’ beneficiaries and covered dependents.

Financing costs

The Company uses the straight line method to amortize financing costs and premiums or discounts over the term of the related long-term debt. Unamortized financing costs and discounts or premiums on long-term debt retired prior to maturity are classified as regulatory assets or liabilities and are amortized on a straight line basis over the remaining original term of the retired debt. The methods and periods for amortizing financing costs, premiums and discounts, including the treatment of these items when long-term debt is retired prior to maturity, have been established by the PUC as part of the rate-making process.

Contributions in aid of construction

The Company receives contributions from customers for special construction requirements. As directed by the PUC, the Company amortizes contributions on a straight-line basis over 30 years as an offset against depreciation expense.

Electric utility revenues

Electric utility 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. Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers for billing purposes is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on the following month meter readings, monthly generation volumes, estimated customer usage by account, line losses and applicable customer rates based on historical values and current rate schedules. At December 31, 2002, customer accounts receivable include unbilled energy revenues of $60 million on a base of annual revenue of $1.3 billion. Revenue amounts recorded pursuant to a PUC interim order are subject to refund, with interest, pending a final order.

The rate schedules of HECO, HELCO and MECO include energy cost adjustment (ECA) 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.

The Company’s operating revenues include amounts for various revenue taxes the electric utilities collect from customers and pay to taxing authorities. Revenue taxes to be paid to the taxing authorities are recorded as an expense and a corresponding liability in the year the related revenues are recognized. Payments to the taxing authorities are made in the subsequent year. For 2002, the Company included $111 million of revenue taxes in “operating revenues” and $113 million (including a $2 million nonrecurring PUC fee adjustment) of revenue taxes

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in “taxes, other than income taxes” expense. For 2001 and 2000, the Company included $114 million and $112 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

Allowance for Funds Used During Construction (AFUDC)

AFUDC is an accounting practice whereby the costs of debt (AFUDC-Debt) and equity (AFUDC-Equity) funds used to finance plant construction are credited on the statement of income and charged to construction in progress on the balance sheet.

The weighted-average AFUDC rate was 8.7% in 2002 and 2001 and 8.6% in 2000, and reflected quarterly compounding.

Environmental expenditures

The Company is subject to numerous federal and state environmental statutes and regulations. 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. Environmental costs are either capitalized or charged to expense when environmental assessments and/or remedial efforts are probable and the cost can be reasonably estimated.

Income taxes

The Company is included in the consolidated income tax returns of HECO’s parent, HEI. Income tax expense has been computed for financial statement purposes as if HECO and its subsidiaries filed separate consolidated HECO income tax returns.

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.

Federal and state tax investment credits are deferred and amortized over the estimated useful lives of the properties which qualified for the credits.

Governmental tax authorities could challenge a tax return position taken by management. If the Company’s position does not prevail, the Company’s results of operations and financial condition may be adversely affected as the related deferred or current income tax asset would be impaired and written down or written off.

Derivative instruments and hedging activities

Derivatives are recognized at fair value in the balance sheet as an asset or liability. Changes in fair value of derivative instruments not designated as hedging instruments are (and the ineffective portions of hedges, if any in the future, would be) recognized in earnings in the current period. In the future, any changes in the fair value of a derivative designated as a fair value hedge and the hedged item would be recorded in earnings. Also, for a derivative designated as a cash flow hedge, the effective portion of changes in fair value of the derivative would be reported in other comprehensive income and subsequently would be reclassified into earnings when the hedged item affects earnings.

Impairment of long-lived assets and long-lived assets to be disposed of

The Company reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell.

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Recent accounting pronouncements and interpretations

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

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

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

Guarantor’s accounting and disclosure requirements for guarantees. In November 2002, the FASB issued Interpretation (FIN) No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” which elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements for periods ending after December 15, 2002 about its obligations under guarantees it has issued. FIN No. 45 also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken. The Company adopted the provisions of FIN No. 45 on January 1, 2003. Since the initial recognition and measurement provisions of FIN No. 45 are applied prospectively to guarantees issued or modified after December 31, 2002, the adoption of FIN No. 45 had no effect on the Company’s historical financial statements.

Consolidation of variable interest entities. In January 2003, the FASB issued FIN No. 46, “Consolidation of Variable Interest Entities,” which addresses the consolidation of variable interest entities (VIEs) as defined. FIN No. 46 applies immediately to variable interests in VIEs created after January 31, 2003, and to variable interests in VIEs obtained after January 31, 2003. For a variable interest in a VIE created before February 1, 2003, FIN No. 46 is applied to the enterprise no later than the beginning of the first interim or annual reporting period beginning after

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June 15, 2003. The application of FIN No. 46 is not expected to have a material effect on the Company’s financial statements.

Reclassifications

Certain reclassifications have been made to prior years’ financial statements to conform to the 2002 presentation.

2. Cumulative preferred stock

The following series of cumulative preferred stock are redeemable only at the option of the respective company and are subject to voluntary liquidation provisions as follows:

Series	Voluntary Liquidation Price December 31, 2002		Redemption Price December 31, 2002
C, D, E, H, J and K (HECO)	$	20.00	$	21.00
I (HECO)		20.00		20.00
G (HELCO)		100.00		—
H (MECO)		100.00		—

HELCO’s series G and MECO’s series H preferred stock may not be redeemed by the respective subsidiary prior to December 2003.

HECO is obligated to make dividend, redemption and liquidation payments on the preferred stock of either of its subsidiaries if the respective subsidiary is unable to make such payments, but such obligation is subordinated to any obligation to make payments on HECO’s own preferred stock.

3. HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO and HECO-guaranteed debentures

December 31	2002		2001		Liquidation value per security
(in thousands, except per security amounts and number of securities)
HECO Capital Trust I* 8.05% Cumulative Quarterly Income Preferred Securities, Series 1997 (2,000,000 securities)**	$	50,000	$	50,000	$	25
HECO Capital Trust II* 7.30% Cumulative Quarterly Income Preferred Securities, Series 1998 (2,000,000 securities)***		50,000		50,000		25
	$	100,000	$	100,000

* Delaware grantor trust.

** Mandatorily redeemable at the maturity of the underlying debt on March 27, 2027, which maturity may be extended to no later than March 27, 2046. Also, redeemable at the issuer’s option after March 27, 2002.

*** Mandatorily redeemable at the maturity of the underlying debt on December 15, 2028, which maturity may be extended to no later than December 15, 2047. Also, redeemable at the issuer’s option after December 15, 2003.

In March 1997, HECO Capital Trust I (Trust I), a grantor trust which is a subsidiary of HECO, sold (i) in a public offering, 2 million of its HECO-Obligated 8.05% Cumulative Quarterly Income Preferred Securities, Series 1997 (1997 trust preferred securities) with an aggregate liquidation preference of $50 million and (ii) to HECO, common securities with a liquidation preference of approximately $1.55 million. Proceeds from the sale of the 1997 trust preferred securities and the common securities were used by Trust I to purchase 8.05% Junior Subordinated Deferrable Interest Debentures, Series 1997 (1997 junior deferrable debentures) issued by HECO in the principal amount of $31.55 million and issued by each of MECO and HELCO in the respective principal amounts of $10 million. The 1997 junior deferrable debentures, which bear interest at 8.05% and mature on March 27, 2027, together with the subsidiary guarantees (pursuant to which the obligations of MECO and HELCO under their respective debentures are fully and unconditionally guaranteed by HECO), are the sole assets of Trust I. The 1997 trust preferred securities must be redeemed at the maturity of the underlying debt on March 27,

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2027, which maturity may be shortened to a date no earlier than March 27, 2002 or extended to a date no later than March 27, 2046, and are not redeemable at the option of the holders, but may be redeemed by Trust I, in whole or in part, from time to time, on or after March 27, 2002 or upon the occurrence of certain events. All of the proceeds from the sale were invested by Trust I in the underlying debt securities of HECO, HELCO and MECO.

In December 1998, HECO Capital Trust II (Trust II), a grantor trust which is a subsidiary of HECO, sold (i) in a public offering, 2 million of its HECO-Obligated 7.30% Cumulative Quarterly Income Preferred Securities, Series 1998 (1998 trust preferred securities) with an aggregate liquidation preference of $50 million and (ii) to HECO, common securities with a liquidation preference of approximately $1.55 million. Proceeds from the sale of the 1998 trust preferred securities and the common securities were used by Trust II to purchase 7.30% Junior Subordinated Deferrable Interest Debentures, Series 1998 (1998 junior deferrable debentures) issued by HECO in the principal amount of $31.55 million and issued by each of MECO and HELCO in the respective principal amounts of $10 million. The 1998 junior deferrable debentures, which bear interest at 7.30% and mature on December 15, 2028, together with the subsidiary guarantees (pursuant to which the obligations of MECO and HELCO under their respective debentures are fully and unconditionally guaranteed by HECO), are the sole assets of Trust II. The 1998 trust preferred securities must be redeemed at the maturity of the underlying debt on December 15, 2028, which maturity may be shortened to a date no earlier than December 15, 2003 or extended to a date no later than December 15, 2047, and are not redeemable at the option of the holders, but may be redeemed by Trust II, in whole or in part, from time to time, on or after December 15, 2003 or upon the occurrence of certain events. All of the proceeds from the sale were invested by Trust II in the underlying debt securities of HECO, HELCO and MECO.

Contractual arrangements (the “Back-up Undertakings”) entered into by HECO in connection with the issuance of the 1997 and 1998 trust preferred securities, considered together, constitute a full and unconditional guarantee by HECO, on a subordinated basis, of the periodic distributions due on the 1997 and 1998 trust preferred securities and of amounts due upon the redemption thereof or upon liquidation of the Trusts. The Back-up Undertakings include HECO’s (i) guarantee that the Trusts will make their respective periodic distributions and redemption and liquidation payments to the extent the Trusts have funds available therefore, (ii) the subsidiary guarantees, (iii) obligations under an agreement to pay all expenses and liabilities of the Trusts (other than the obligation of the Trusts to pay amounts due to the holders of the 1997 and 1998 trust preferred securities) and (iv) obligations under the trust agreements, HECO’s 1997 and 1998 junior subordinated debentures and the respective indentures pursuant to which the 1997 and 1998 junior subordinated debentures were issued. The 1997 and 1998 junior deferrable debentures and the common securities of the Trusts have been eliminated in HECO’s consolidated balance sheets as of December 31, 2002 and 2001. The 1997 and 1998 junior deferrable debentures are redeemable only (i) at the option of HECO, MECO and HELCO, respectively, in whole or in part, on or after March 27, 2002 (1997 junior deferrable debentures) and December 15, 2003 (1998 junior deferrable debentures) or (ii) at the option of HECO, in whole, upon the occurrence of a “Special Event” (relating to certain changes in laws or regulations).

4. Long-term debt

The first mortgage bonds of HELCO were secured by a mortgage which purported to be a lien on substantially all of the real and personal property owned or acquired by HELCO. The remaining two series of these bonds were redeemed in early 2002 and the mortgage was released.

For special purpose revenue bonds, the funds on deposit with trustees represent the undrawn proceeds from the issuance of the special purpose revenue bonds and earn interest at market rates. These funds are available only to pay (or reimburse payment of) expenditures in connection with certain authorized construction projects and certain expenses related to the bonds.

In September 2002, the Department of Budget and Finance of the State of Hawaii issued tax-exempt special purpose revenue bonds in the principal amount of $40 million with a maturity of 30 years and a fixed coupon interest rate of 5.10%, and loaned the proceeds from the sale to HECO.

At December 31, 2002, the aggregate payments of principal required on long-term debt during the next five years are nil in each year.

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In January 2003, MECO’s proportionate share of the 6.55% Series 1992 Special Purpose Revenue Bonds, in the principal amount of $8.0 million, was called for redemption on March 12, 2003.

5. Short-term borrowings

There were no short-term borrowings from nonaffiliates at December 31, 2002 or 2001.

At December 31, 2002 and 2001, the Company maintained bank lines of credit which totaled $100 million ($20 million maturing in March 2003, $30 million maturing in April 2003, $10 million maturing in May 2003 and $40 million maturing in June 2003) and $110 million, respectively. On January 1, 2003, HECO reduced its total lines of credit to $90 million, thereby reducing to $30 million the lines maturing in June 2003. The Company maintains lines of credit to support the issuance of commercial paper and for other general corporate purposes. None of the lines are secured. There were no borrowings under any line of credit at December 31, 2002 or during 2002. The Company borrowed and repaid $8.8 million under a line of credit in 2001.

6. Regulatory assets

In accordance with SFAS No. 71, the Company’s consolidated financial statements reflect assets and costs based on current cost-based rate-making regulations. Continued accounting under SFAS No. 71 requires that certain criteria be met. Management believes the Company’s operations currently satisfy the criteria. However, if events or circumstances change so that the criteria are no longer satisfied, management believes that a material adverse effect on the Company’s financial statements may result as the regulatory assets would be charged to expense.

Regulatory assets are expected to be fully recovered through rates over PUC authorized periods ranging from one to 36 years (periods noted in parenthesis) and include the following deferred costs:

December 31,	2002		2001
(in thousands)
Income taxes (1 to 36 years)	$	64,278	$	62,467
Postretirement benefits other than pensions (10 years)		17,897		19,687
Unamortized expense and premiums on retired debt and equity issuances (2 to 26 years).		11,005		12,100
Integrated resource planning costs (1 year)		1,965		6,243
Vacation earned, but not yet taken (1 year)		4,776		4,929
Other (1 to 4 years)		5,647		5,950
	$	105,568	$	111,376

Regulatory asset related to Barbers Point Tank Farm project costs

In December 1991, HECO filed an application with the PUC for the installation of a nominal 200 megawatt (MW) combined cycle power plant. Due to changes in circumstances, the expected timing for HECO’s next generating unit was significantly delayed, and HECO withdrew its application in May 1993. In August 1994, HECO informed the PUC that, consistent with past and current company practices, the accumulated project costs would be allocated primarily to ongoing active capital projects. The PUC advised HECO to file an application, which it did in February 1995, citing project costs of $5.8 million. The Consumer Advocate objected to the accounting treatment proposed by HECO. To simplify and expedite the proceeding, in September 2000, HECO and the Consumer Advocate reached an agreement on the accounting treatment, subject to PUC approval. Acceptance of the agreement by the parties was without prejudice to any position either of them may take in any subsequent proceeding. Under the agreement, $4.5 million of the $5.8 million total project costs would be amortized to operating expense ratably over a five-year period. In September 2000, HECO adjusted the project costs by $1.3 million to reflect the agreement with the Consumer Advocate, resulting in an after tax write-off of $0.8 million. In September 2001, HECO received PUC approval to amortize $4.5 million over a five-year period, which HECO began in October 2001.

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Integrated Resource Planning costs

In 1992, the PUC established a framework for Integrated Resource Planning (IRP) and ordered the companies to develop an integrated resource plan in accordance with the IRP framework. The framework also provides that the utilities are entitled to recover appropriate IRP and implementation costs. Each year, HECO, HELCO and MECO submit a budget of the IRP costs for the upcoming year, and request subsequent recovery of the actual costs incurred. Actual IRP costs incurred since 1995 have been recorded as a regulatory asset, and are charged to expense as the Company recovers those costs through rates.

The PUC has allowed the Company to recover IRP costs pending the PUC’s final decision and order approving recovery of each respective year’s IRP costs. Recovery of IRP costs is subject to refund with interest. HECO has been allowed and has fully recovered its deferred IRP costs for years 1995 through 2001. MECO has been allowed to recover its deferred IRP costs for years 1995 through 2001, and is currently recovering costs incurred for year 2001. HELCO has been allowed and has fully recovered its deferred IRP costs for years 1995 through 2000. HELCO’s costs for year 2001 and subsequent years are included in its base rates. As of December 31, 2002, the amount of revenues recorded, subject to refund with interest, amounted to $16.0 million.

7. Income taxes

The components of income taxes charged to operating expenses were as follows:

December 31,	2002			2001			2000
(in thousands)
Federal:
Current	$	37,481		$	41,120		$	43,206
Deferred		13,337			8,584			6,243
Deferred tax credits, net		(1,557	)		(1,567	)		(1,585	)
		49,261			48,137			47,864
State:
Current		5,369			3,272			5,446
Deferred		1,068			1,549			921
Deferred tax credits, net		1,031			2,476			982
		7,468			7,297			7,349
Total	$	56,729		$	55,434		$	55,213

Income tax benefits related to nonoperating activities, included in “Other, net” on the consolidated statements of income, amounted to $71,000, $18,000 and $162,000 for 2002, 2001 and 2000, respectively.

A reconciliation between income taxes charged to operating expenses and the amount of income taxes computed at the federal statutory rate of 35% on income before income taxes and preferred stock dividends follows:

December 31,	2002			2001			2000
(in thousands)
Amount at the federal statutory income tax rate	$	52,226		$	51,005		$	50,573
State income taxes on operating income, net of effect on federal income taxes		4,854			4,743			4,777
Other		(351	)		(314	)		(137	)
Income taxes charged to operating expenses	$	56,729		$	55,434		$	55,213

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The tax effects of book and tax basis differences that give rise to deferred tax assets and liabilities were as follows:

December 31,	2002		2001
(in thousands)
Deferred tax assets:
Property, plant and equipment	$	12,801	$	12,488
Contributions in aid of construction and customer advances		46,052		47,546
Other		13,213		12,382
		72,066		72,416
Deferred tax liabilities:
Property, plant and equipment		174,832		170,559
Regulatory assets		24,794		24,313
Other		30,807		23,152
		230,433		218,024
Net deferred income tax liability	$	158,367	$	145,608

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. Based upon historical taxable income, projections for future taxable income and tax planning strategies, management believes it is more likely than not the Company will realize the benefits of the deferred tax assets and has provided no valuation allowance for deferred tax assets during 2002, 2001 and 2000.

8. Cash flows

Supplemental disclosures of cash flow information

Cash paid during 2002, 2001 and 2000 for interest (net of AFUDC-Debt) and income taxes was as follows:

December 31,	2002		2001		2000
(in thousands)
Interest	$	45,230	$	43,519	$	44,020
Income taxes	$	47,530	$	38,392	$	56,875

Supplemental disclosures of noncash activities

The allowance for equity funds used during construction, which was charged primarily to construction in progress, amounted to $4.0 million, $4.2 million and $5.4 million in 2002, 2001 and 2000, respectively.

The estimated fair value of noncash contributions in aid of construction amounted to $4.4 million, $2.4 million and $6.6 million in 2002, 2001 and 2000, respectively.

In 2002, HECO assigned accounts receivable totaling $10.5 million to a creditor, without recourse, in full settlement of HECO’s $10.5 million notes payable to the creditor.

9. Major customers

HECO and its subsidiaries derived approximately 9% of their operating revenues from the sale of electricity to various federal government agencies in 2002 and 10% in 2001 and 2000. These revenues amounted to $119 million in 2002, $127 million in 2001 and $123 million in 2000.

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10. Retirement benefits

Pensions

Substantially all of the employees of the Company participate in the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries (Plan). The Plan is a qualified, non-contributory defined benefit pension plan with the benefits for union employees determined in accordance with the terms of the collective bargaining agreements between the Company and their respective unions. The Plan is subject to the provisions of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In addition, some current and former executives and directors of the Company participate in noncontributory, nonqualified plans (collectively, Supplemental/Excess/Directors Plans). In general, benefits are based on the employees’ years of service and compensation.

The Plan and the Supplemental/Excess/Directors Plans were adopted with the expectation that they will continue indefinitely, but the continuation of these plans and the payment of any contribution thereunder is not assumed as a contractual obligation by the participating employers. Each participating employer reserves the right to terminate its participation in the applicable plan at any time, and HEI reserves the right to terminate its respective plan at any time. If a participating employer terminated its participation in the Plan, the interest of each affected participant would become 100% vested to the extent funded. Upon the termination of the Plan, assets would be distributed to affected participants in accordance with the applicable allocation provisions of ERISA and any excess assets that exist would be paid to the Participating Employers. Participants’ benefits are covered up to certain limits under insurance provided by the Pension Benefit Guaranty Corporation (PBGC).

The Participating Employers contribute amounts to a master pension trust (Trust) for the Plan in accordance with the funding requirements of ERISA and considering the deductibility of contributions under the Internal Revenue Code (Code). The funding of the Plan is based on actuarial assumptions adopted by the Pension Investment Committee administering the Plan on the advice of an enrolled actuary.

To determine pension costs for the Company under the Plan and the supplemental/Excess/Directors Plans, it is necessary to make complex calculations and estimates based on numerous assumptions, including the weighted-average assumptions identified below.

Postretirement benefits other than pensions

The Company provides eligible employees health and life insurance benefits upon retirement under the Postretirement Welfare Benefits Plan for Employees of Hawaiian Electric Company, Inc. and Participating Employers. The amount of health benefits is based on retirees’ years of service and retirement date. Generally, employees are eligible for these benefits if, upon retirement, they participate in the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries.

The postretirement benefits plan was adopted with the expectation that it will continue indefinitely, but the continuation of the plan and the payment of any contribution thereunder is not assumed as a contractual obligation by the participating employers. Each participating employer reserves the right to terminate its participation in the postretirement benefits plan at any time.

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Pension and other postretirement benefit plans information

The changes in the pension and other postretirement benefit defined benefit plans’ obligations and plan assets, the funded status of the plans and the unrecognized and recognized amounts reflected in the balance sheet were as follows:

	Pension benefits						Other benefits
(in thousands)	2002			2001			2002			2001
Benefit obligation, January 1	$	591,036		$	552,030		$	143,055		$	122,161
Service cost		16,965			16,317			3,028			2,951
Interest cost		41,891			40,073			9,920			9,128
Amendments		—			(217	)		—			—
Actuarial loss		46,578			15,170			6,004			15,344
Benefits paid		(34,181	)		(32,337	)		(6,369	)		(6,529	)
Benefit obligation, December 31		662,289			591,036			155,638			143,055
Fair value of plan assets, January 1		677,590			788,955			88,448			102,265
Actual loss on plan assets		(91,778	)		(79,291	)		(13,927	)		(11,264	)
Employer contribution		328			242			6,382			3,976
Benefits paid		(34,173	)		(32,316	)		(6,369	)		(6,529	)
Fair value of plan assets, December 31		551,967			677,590			74,534			88,448
Funded status		(110,322	)		86,554			(81,104	)		(54,607	)
Unrecognized net actuarial loss (gain)		185,270			(32,930	)		23,604			(6,915	)
Unrecognized net transition obligation		960			3,223			32,642			35,907
Unrecognized prior service gain		(8,031	)		(8,781	)		—			—
Net amount recognized, December 31	$	67,877		$	48,066		$	(24,858	)	$	(25,615	)
Amounts recognized in the balance sheet consist of:
Prepaid benefit cost	$	70,635		$	50,817		$	—		$	—
Accrued benefit liability		(2,758	)		(2,751	)		(24,858	)		(25,615	)
Net amount recognized, December 31	$	67,877		$	48,066		$	(24,858	)	$	(25,615	)

The following weighted-average assumptions were used in the accounting for the plans:

	Pension benefits						Other benefits
December 31,	2002		2001		2000		2002		2001		2000
Discount rate	6.75	%	7.25	%	7.50	%	6.75	%	7.25	%	7.50	%
Expected return on plan assets	9.0		10.0		10.0		9.0		10.0		10.0
Rate of compensation increase	4.6		4.6		4.6		4.6		4.6		4.6

At December 31, 2002, the assumed health care trend rates for 2003 and future years were as follows: medical, 9.28%, grading down to 4.25%; dental, 4.25%; and vision, 3.25%. At December 31, 2001, the assumed health care trend rates for 2002 and future years were as follows: medical, 10.00%, grading down to 4.75%; dental, 4.75%; and vision, 3.75%.

The components of the net periodic benefit cost (return) were as follows:

	Pension benefits									Other benefits
(in thousands)	2002			2001			2000			2002			2001			2000
Service cost	$	16,965		$	16,317		$	15,385		$	3,028		$	2,951		$	2,737
Interest cost		41,891			40,073			38,526			9,920			9,128			8,742
Expected return on plan assets		(76,169	)		(75,644	)		(70,460	)		(9,872	)		(9,882	)		(9,189	)
Amortization of unrecognized transition obligation		2,263			2,273			2,273			3,264			3,264			3,264
Amortization of prior service gain		(750	)		(750	)		(703	)		—			—			—
Recognized actuarial gain		(3,683	)		(8,210	)		(9,398	)		(716	)		(2,597	)		(3,112	)
Net periodic benefit cost (return)	$	(19,483	)	$	(25,941	)	$	(24,377	)	$	5,624		$	2,864		$	2,442

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Of the net periodic pension benefit costs (returns), the Company recorded income of approximately $14.3 million in 2002, $19.0 million in 2001 and $18.2 million in 2000, respectively, and credited the remaining amounts primarily to electric utility plant. Of the net periodic other benefit costs, the Company expensed $4.1 million, $2.1 million and $1.8 million in 2002, 2001 and 2000, respectively, and charged the remaining amounts primarily to electric utility plant.

At December 31, 2002 and 2001, the Company had pension plans in which the accumulated benefit obligations exceeded plan assets at fair value, but such plans did not have material benefit obligations.

The health care cost trend rate assumptions can have a significant effect on the amounts reported for other benefits. At December 31, 2002, a one-percentage-point increase in the assumed health care cost trend rates would have increased the total service and interest cost by $0.3 million and the postretirement benefit obligation by $3.7 million, and a one-percentage-point decrease would have reduced the total service and interest cost by $0.3 million and the postretirement benefit obligation by $4.4 million.

11. Commitments and contingencies

Fuel contracts

The Company has contractual agreements to purchase minimum quantities of fuel oil and diesel fuel through 2004 (at prices tied to the market prices of petroleum products in Singapore and Los Angeles). Based on the average price per barrel at January 1, 2003, the estimated cost of minimum purchases under the fuel supply contracts for 2003 is $329 million. The actual cost of purchases in 2003 could vary substantially from this estimate as a result of changes in market prices, quantities actually purchased and/or other factors. The Company purchased $317 million, $328 million and $359 million of fuel under contractual agreements in 2002, 2001 and 2000, respectively.

Power purchase agreements

At December 31, 2002, the Company had power purchase agreements for 534 MW of firm capacity. The PUC allows rate recovery for energy and firm capacity payments under these agreements. Assuming that each of the agreements remains in place for its current term and the minimum availability criteria in the power purchase agreements are met, aggregate minimum fixed capacity charges are expected to be approximately $123 million each in 2003 and 2004, $118 million each in 2005, 2006 and 2007 and a total of $1.6 billion in the period from 2008 through 2030.

In general, the Company bases its payments under the power purchase agreements upon available capacity and energy and is generally not required to make payments for capacity if the contracted capacity is not available, and payments are reduced, under certain conditions, if available capacity drops below contracted levels. In general, the payment rates for capacity have been predetermined for the terms of the agreements. Energy payments will vary over the terms of the agreements and the Company passes on changes in the fuel component of the energy charges to customers through the ECA clause in the rate schedules. The Company does not operate nor participate in the operation of any of the facilities that provide power under the agreements. Title to the facilities does not pass to the Company upon expiration of the agreements, and the agreements do not contain bargain purchase options for the facilities.

Interim increases

At December 31, 2002, HECO and its electric utility subsidiaries recognized $16.0 million of revenues with respect to interim orders regarding certain integrated resource planning costs, which revenues are subject to refund, with interest, if and to the extent they exceed the amounts allowed in final orders.

HELCO power situation

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

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installed and “is used and useful for utility purposes.” The PUC at that time also ordered HELCO to continue negotiating with independent power producers (IPPs), stating that the facility to be built should be the one that can be most expeditiously put into service at “allowable cost.”

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

As a result of a September 19, 2002 decision by the Third Circuit Court of the State of Hawaii (Circuit Court), relating to an extension of a construction deadline and described below under “Land use permit amendment,” the construction of CT-4 and CT-5, which had commenced in April 2002 after HELCO had obtained a final air permit and the Circuit Court had lifted a stay on construction, has been suspended. HELCO has appealed this ruling to the Hawaii Supreme Court and is considering other options that may allow HELCO to complete the installation of CT-4 and CT-5 (including seeking a land use reclassification of the Keahole site from the State Land Use Commission). If none of these options is ultimately successful, or if other permitting issues or problems arise which HELCO cannot satisfactorily resolve, HELCO may be unable to complete the installation of CT-4 and CT-5.

The following is a detailed discussion of the existing Keahole situation, including a description of its potential financial statement implications under “Management’s evaluation; costs incurred.”

Land use permit amendment. The Circuit Court ruled in 1997 that because the BLNR had failed to render a valid decision on HELCO’s application to amend its land use permit before the statutory deadline in April 1996, HELCO was entitled to use its Keahole site for the expansion project (HELCO’s “default entitlement”). Final judgments of the Circuit Court related to this ruling are on appeal to the Hawaii Supreme Court, which in 1998 denied motions to stay the Circuit Court’s final judgment pending resolution of the appeal.

The Circuit Court’s final judgment provided that HELCO must comply with the conditions in its application and with the standard land use conditions insofar as those conditions were not inconsistent with HELCO’s default entitlement. There have been numerous proceedings before the Circuit Court and the BLNR in which certain parties (a) have sought determinations of what conditions apply to HELCO’s default entitlement, (b) have claimed that HELCO has not complied with applicable land use conditions and that its default entitlement should thus be forfeited, (c) have claimed that HELCO will not be able to operate the proposed plant without violating applicable land use conditions and provisions of Hawaii’s Air Pollution Control Act and Noise Pollution Act and (d) have sought orders enjoining any further construction at the Keahole site.

Although there has not been a final resolution of these claims, there have been several significant rulings relating to these claims, some of which may adversely affect HELCO’s ability to construct and efficiently operate CT-4 and CT-5. First, based on a change by the DOH in its interpretation of the noise rules it promulgated under the Hawaii Noise Pollution Act, the Circuit Court ruled that a stricter noise standard than the previously applied standard applies to HELCO’s plant, but left enforcement of the ruling to the DOH. HELCO filed a separate complaint for declaratory relief against the DOH seeking the invalidation of the noise rules on constitutional and other grounds. The Circuit Court denied HELCO’s motion for summary judgment, finding that the noise rules are constitutional on their face but specifically not ruling on the constitutionality of the rules as applied to Keahole. HELCO appealed the final judgment to the Hawaii Supreme Court in August 1999 and a decision on that appeal is pending. The DOH has been periodically monitoring noise levels at the site. If the DOH were to issue a notice of violation based on the stricter standards, HELCO may, among other things, assert that the noise regulations, as applied to it at Keahole, are unconstitutional. Meanwhile, while not waiving possible claims or defenses that it might have against the DOH, HELCO has installed noise mitigation measures on the existing units at Keahole and, should construction be allowed to continue, is planning to implement additional noise mitigation measures for both the existing units and for CT-4 and CT-5. The estimated cost for these additional noise mitigation measures

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(for the existing units and CT-4 and CT-5) is $5 million, which would be capitalized. While the noise mitigation measures were being implemented, HELCO applied to the DOH and received approval for a noise permit through 2003, which has since been extended to July 2007.

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

Keahole Defense Coalition, Inc. (KDC) and two individuals appealed the BLNR’s March 25, 2002 Order to the Circuit Court, as did the Department of Hawaiian Home Lands. On September 19, 2002, the Circuit Court issued a letter to the parties indicating the Circuit Court’s decision to reverse the BLNR’s Order. The letter states that:

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

2. The conclusions of law are erroneous.

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

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

The Circuit Court issued an Order to this effect on October 3, 2002.

On November 1, 2002, HELCO filed a notice of appeal of the October 3, 2002 Order (which appeal will be decided by the Hawaii Supreme Court or Hawaii Intermediate Court of Appeals). On November 15, 2002, HELCO also filed with the Hawaii Supreme Court a Motion for Stay Pending Disposition of Appeal and a Motion to Expedite Transmission of Record on Appeal. The Motion to Expedite was denied on December 10, 2002. The Motion for Stay was denied in early 2003. On November 25, 2002, KDC and two individuals filed with the Supreme Court a Motion to Dismiss this appeal on the basis that the case was moot, since HELCO no longer had a default entitlement because it allegedly violated the BLNR’s March 25, 2002 Order by withdrawing its application to the LUC for a boundary amendment. That motion was denied in early 2003. Accordingly, the Hawaii Supreme Court continues to assert jurisdiction over this appeal and briefs will be filed.

On November 1, 2002, HELCO filed with the Circuit Court a notice of appeal of the original November 9, 2000 ruling that the three-year deadline had expired in April 1999. In early 2003, the Supreme Court dismissed that appeal for lack of jurisdiction. The Supreme Court’s Order stated that HELCO’s appeal was not timely filed

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because it was not filed within 30 days of the Circuit Court’s November 9, 2000 Order, even though the Circuit Court ruled at the time that its Order could not yet be appealed.

In the meantime, construction activities on CT-4 and CT-5 have been suspended and steps have been taken to secure the site and protect equipment and personnel.

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

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

Land Use Commission petition. One of the conditions of the construction period extension granted by the BLNR (which the Circuit Court’s October 3, 2002 Order now has reversed) was that HELCO file an application for a boundary amendment with the LUC to remove the site from the conservation district. HELCO filed the application on June 21, 2002. A hearing before the LUC was held on September 12, 2002, at which public testimony was taken and memoranda were received regarding the jurisdiction of the LUC in dealing with the HELCO petition. In light of subsequent events, HELCO withdrew its petition on October 3, 2002. Under LUC rules, after such a voluntary withdrawal the applicant may submit another petition for the same property one year from the date of withdrawal. HELCO intends to submit a new petition for reclassification in the fourth quarter of 2003.

IPP Complaints. Three IPPs—Kawaihae Cogeneration Partners (KCP), Enserch Development Corporation (Enserch) and Hilo Coast Power Company (HCPC)—filed separate complaints with the PUC in 1993, 1994 and 1999, respectively, alleging that they are each entitled to a power purchase agreement (PPA) to provide HELCO with additional capacity. KCP and Enserch each claimed they would be a substitute for HELCO’s planned expansion of Keahole.

The Enserch and HCPC complaints have been resolved by HELCO’s entry into two PPAs, which were necessary to ensure reliable service to customers on the island of Hawaii, but, in the opinion of management, do not supplant the need for CT-4 and CT-5. HELCO can terminate the PPA with HCPC prior to its 2004 expiration date, for a fee.

In October 1999, the Circuit Court ruled that the lease for KCP’s proposed plant site was invalid. In January 2003, the PUC issued an order denying KCP’s July 1999 request to reopen KCP’s 1993 complaint docket and to enforce the Public Utility Regulatory Policies Act of 1978. Based on these rulings and for other reasons, management believes that KCP’s proposal for a PPA is not viable and, therefore, will not impact the need for CT-4 and CT-5.

Management’s evaluation; costs incurred. In addition to the appeal of the October 3, 2002 Circuit Court’s Order filed on November 1, 2002, HELCO is considering other options that may allow HELCO to complete the installation of CT-4 and CT-5, including seeking a land use reclassification of the Keahole site from the State Land Use Commission. At this time, the likelihood of success of any of these options cannot be ascertained. Even if the Circuit Court’s Order is ultimately overturned on appeal, however, construction is likely to be further significantly delayed, and the costs to complete construction may be significantly increased, due to the time that is likely to be required to resolve the legal proceedings. In the meantime, one concern of HELCO’s management is the condition and performance of certain aging generators on the HELCO system, which were intended to be retired or to be operated less frequently once CT-4 and CT-5 were installed, as well as the current operating status of various IPPs, which provide approximately 43% of HELCO’s generating capacity. Another concern is the possibility of

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power interruptions under exigent circumstances, including rolling blackouts, as IPPs and/or HELCO’s generating units become unavailable or less available (i.e., available at lower capacity) due to forced outages or planned maintenance. Such incidents occurred or were at risk of occurring on October 3, 2002 and November 8, 2002. As it has done on such occasions in the past, HELCO will endeavor to avert power interruptions, including rolling blackouts, in the future through a number of actions in addition to managing the generating units on its system, such as requesting customers to reduce demand during critical periods such as the peak evening hours. Under current system conditions, however, there can be no assurance that power interruptions will not occur.

The recovery of costs relating to CT-4 and CT-5 are subject to the rate-making process governed by the PUC. Management believes no adjustment to costs incurred to put CT-4 and CT-5 into service is required as of December 31, 2002. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HELCO may be required to write off a material portion of the costs incurred in its efforts to put these units into service whether or not CT-4 and CT-5 are installed. As of December 31, 2002, HELCO’s costs incurred in its efforts to put CT-4 and CT-5 into service and to support existing units (excluding costs the PUC permitted to be transferred to plant-in-service for pre-air permit facilities) amounted to approximately $82 million, including $32 million for equipment and material purchases, $30 million for planning, engineering, permitting, site development and other costs and $20 million for AFUDC. In addition to the $82 million in construction in progress, construction and/or purchase commitments related to CT-4 and CT-5 outstanding as of December 31, 2002 are estimated at approximately $0.6 million.

Although management believes it has acted prudently with respect to the Keahole project, effective December 1, 1998, HELCO discontinued the accrual of AFUDC on CT-4 and CT–5 due in part to the delays through that date and the potential for further delays. HELCO has also deferred plans for ST-7 to a date outside the near-term planning horizon. No costs for ST-7 are included in construction in progress.

Oahu transmission system

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

Construction of the Kamoku to Pukele transmission line in its 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 have opposed the project, particularly the overhead portion of the line.

In November 2000, the DLNR accepted a Revised Final Environmental Impact Statement (RFEIS) prepared in support of HECO’s application for a CDUP. In January 2001, three organizations and an individual filed a complaint against the DLNR and HECO challenging the DLNR’s acceptance of the RFEIS and seeking, among other things, a judicial declaration that the RFEIS is inadequate and null and void. HECO continues to contest the lawsuit.

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

HECO continues to believe that the proposed project is needed. The project would address future potential transmission line overloads in the Northern and Southern corridors under certain contingencies (in which one of the three lines feeding power to the Koolau/Pukele area served by the Northern Corridor, or to the downtown Honolulu area served by the Southern Corridor, is out for maintenance, and a second line incurs an unexpected outage), and improves the reliability of the Pukele substation. The line overload contingencies could occur, given current load growth forecasts, in 2005 for the Northern Corridor, but not until 2013 or later in the Southern Corridor. The Pukele substation, at the end of the Northern corridor, serves approximately 18% of Oahu’s

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electrical load, including Waikiki. If one of the 138 kV transmission lines to the Pukele substation fails while the other is out for maintenance, a major system outage would result.

HECO is evaluating alternative ways to accomplish the project, and possible future actions to expedite PUC review of the alternatives (and the need for the project). Until this evaluation of alternatives is completed, an estimated project completion date cannot be determined.

As of December 31, 2002, the accumulated costs related to the Kamoku to Pukele transmission line amounted to $17 million, including $12 million for planning, engineering and permitting costs and $5 million for AFUDC. These costs are recorded in construction in progress. The recovery of costs relating to the Kamoku to Pukele transmission line is subject to the rate-making process administered by the PUC. Management believes no adjustment to project costs incurred is required as of December 31, 2002. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HECO may be required to write off a material portion or all of the project costs incurred in its efforts to put the Kamoku to Pukele transmission line into service whether or not the project is completed.

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

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

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

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

On May 22, 2002, AES, with the consent of HECO and HEI, removed the case to the U.S. District Court for the District of Hawaii (District Court) on the ground that the action arises under and is completely preempted by the Public Utility Regulatory Policies Act of 1978.

On June 12, 2002, HECO and HEI filed a motion to dismiss the complaint on the grounds that the plaintiffs’ claims either arose prior to enactment of the Hawaii False Claims Act, which does not have retroactive application, or are barred by the applicable statute of limitations. AES also filed a motion to dismiss, on the same and additional grounds.

Plaintiffs moved to remand the case to state court on June 21, 2002. On November 14, 2002, the District Court Judge remanded the case back to state court and denied plaintiffs’ request for attorneys’ fees and costs.

On December 20, 2002, HECO and HEI re-filed their motion to dismiss the complaint. AES joined in the motion. At a hearing on the motion in early 2003, the First Circuit Court ordered dismissal of the qui tam claims relating to actions prior to May 26, 2000, the effective date of the Hawaii False Claims Act, on the ground that the

45

Act did not have retroactive application. Subsequently, the First Circuit Court issued a minute order dismissing Plaintiffs’ claims for (1) violations of Hawaii’s Unfair and Deceptive Practices Act, (2) unjust enrichment/restitution and (3) fraud, which claims were purportedly brought as a class action, on the ground that all of these claims were barred by the applicable statutes of limitations.

As a result of the Circuit Court’s ruling, the only claim that appears to remain is under the Hawaii False Claims Act based on allegations that false bills or claims were submitted to the State after May 26, 2000. Under the False Claims Act a defendant may be liable to a qui tam plaintiff for treble damages, plus civil penalties of a minimum of $5,000 for each false claim, plus attorneys’ fees and costs incurred in the action. The Plaintiffs appear to claim that each monthly bill submitted to each state agency and office on Oahu constitutes a separate false claim.

Management intends to vigorously defend the lawsuit.

Environmental regulation

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

In 1999, the Work Group submitted reports to the DOH presenting environmental conditions and recommendations for additional data gathering to allow for an assessment of the need for risk-based corrective action. The Work Group also engaged a consultant who identified 27 additional potentially responsible parties (PRPs) who were not members of the Work Group.

In response to the DOH’s request for technical assistance, the EPA became involved with the harbor investigation in June 2000. In November 2000, the DOH issued notices to over 20 other PRPs regarding the ongoing investigation in the Honolulu Harbor area. A new voluntary agreement and a joint defense agreement were signed by the parties in the Work Group and some of the new PRPs, including Phillips Petroleum. The group is now called the Iwilei District Participating Parties (Participating Parties). The Participating Parties agreed to fund remediation work using an interim cost allocation method.

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

In September 2001, the EPA and DOH concurrently issued notices of interest (collectively, the Second NOI) to the members of the Participating Parties, including HECO. The Second NOI identified several investigative and preliminary oil removal tasks to be taken at certain valve control facilities associated with historic pipelines in the Iwilei Unit of the Honolulu Harbor site. The Participating Parties performed the tasks identified in the Second NOI (the Phase I Pipeline Investigation) and developed a proposal for additional investigation (the Phase 2 Pipeline Investigation), which proposal the EPA and DOH approved. The Participating Parties have completed the Phase 2 Pipeline Investigation and anticipate submitting a report to the DOH and EPA in the first quarter of 2003. With the approval of the EPA and DOH, the Participating Parties also constructed a pilot Dual Phase Extraction System to remove petroleum liquids and vapors from the subsurface in a portion of the Iwilei District. Operation of the pilot extraction system began in October 2002. The pilot study supplements ongoing petroleum removal activities by the Participating Parties from wells and trenches installed as part of the investigation. The Participating Parties are currently updating the Conceptual Site Model for the Iwilei Unit, In addition, the Participating Parties plan to

46

undertake a Feasibility Study during 2003 to identify and evaluate various remedial strategies to address petroleum products identified in the subsurface of the Iwilei District. Based on the Conceptual Site Model and the Feasibility Study, the Participating Parties will also recommend implementation of remedial strategies, where appropriate.

In October 2002, HECO and three other companies that currently have petroleum handling operations (the Operating Companies) in the Iwilei Unit entered into an agreement with the DOH to evaluate their facilities to determine whether they currently are releasing petroleum to the subsurface in the Iwilei Unit. HECO has previously investigated its facilities in the Iwilei Unit and routinely maintains them, and therefore believes that the Operating Companies evaluation will confirm that HECO’s current operations are not releasing petroleum in the Iwilei Unit.

Management has developed a preliminary estimate of costs for continuing investigative work, remedial activities and monitoring at the Iwilei Unit of the site. Management estimates that HECO will incur approximately $1.1 million (of which $0.2 million has been incurred through December 31, 2002) in connection with work to be performed at the site primarily from January 2002 through December 2004. This estimate was expensed in 2001. However, because (1) the full scope and extent of additional investigative work, remedial activities and monitoring are unknown at this time, (2) the final cost allocation method has not yet been determined and (3) management cannot estimate the costs to be incurred (if any) for the sites other than the Iwilei Unit (including its Honolulu power plant site), the cost estimate may be subject to significant change and additional material investigative and remedial costs may be incurred after December 2004.

Collective bargaining agreements

Approximately 62% of the employees of HECO, HELCO and MECO are represented by the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260 (IBEW), and are covered by collective bargaining agreements, which expire at midnight on October 31, 2003. Should the IBEW not reach agreements with HECO, HELCO and MECO in a timely manner upon the expiration of the existing agreements, HECO and its subsidiaries’ results of operations could be adversely affected.

12. Regulatory restrictions on distributions to parent

At December 31, 2002, net assets (assets less liabilities and preferred stock) of approximately $452 million were not available for transfer to HEI in the form of dividends, loans or advances without regulatory approval.

13. Related-party transactions

HEI charged HECO and its subsidiaries $2.2 million, $2.0 million and $1.8 million for general management and administrative services in 2002, 2001 and 2000, respectively. The amounts charged by HEI to its subsidiaries are allocated primarily on the basis of actual labor hours expended in providing such services.

HEI also charged HECO $2.1 million, $2.2 million and $2.5 million for data processing services in 2002, 2001 and 2000, respectively.

HECO’s borrowings from HEI fluctuate during the year, and totaled $5.6 million and $48.3 million at December 31, 2002 and 2001, respectively. The interest charged on short-term borrowings from HEI is based on the rate HEI pays on its commercial paper, provided HEI’s commercial paper rating is equal to or better than HECO’s rating. If HEI’s commercial paper rating falls below HECO’s, interest is based on HECO’s short-term external borrowing rate, or quoted rates from the Wall Street Journal for 30-day dealer-placed commercial paper.

Interest charged by HEI to HECO totaled $0.4 million, $1.2 million and $0.1 million in 2002, 2001 and 2000, respectively.

14. Significant group concentrations of credit risk

HECO and its utility subsidiaries are regulated operating electric public utilities engaged in the generation, purchase, transmission, distribution and sale of electricity on the islands of Oahu, Hawaii, Maui, Lanai and Molokai in the State of Hawaii. HECO and its utility subsidiaries provide the only electric public utility service on the islands they serve. HECO and its utility subsidiaries grant credit to customers, all of whom reside or conduct business in the State of Hawaii.

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15. Fair value of financial instruments

The Company used the following methods and assumptions to estimate the fair value of each applicable class of financial instruments for which it is practicable to estimate that value:

Cash and equivalents and short-term borrowings

The carrying amount approximated fair value because of the short maturity of these instruments.

Long-term debt

Fair value was estimated based on quoted market prices for the same or similar issues of debt.

HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO and HECO-guaranteed debentures

Fair value was based on quoted market prices.

The estimated fair values of the financial instruments held or issued by the Company were as follows:

December 31,	2002				2001
	Carrying Amount		Estimated fair value		Carrying amount		Estimated fair value
(in thousands)
Financial assets:
Cash and equivalents	$	1,726	$	1,726	$	1,858	$	1,858
Financial liabilities:
Short-term borrowings from affiliate		5,600		5,600		48,297		48,297
Long-term debt, net, including amounts due within one year		705,270		735,694		685,269		665,849
HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO and HECO-guaranteed debentures		100,000		100,120		100,000		100,400

Limitations

The Company makes fair value estimates at a specific point in time, based on relevant market information and information about the financial instrument. These estimates do not reflect any premium or discount that could result if the Company were to sell its entire holdings of a particular financial instrument at one time. Because no market exists for a significant portion of the Company’s financial instruments, fair value estimates cannot be determined with precision. Changes in assumptions could significantly affect the estimates.

Fair value estimates are provided for certain financial instruments without attempting to estimate the value of anticipated future business and the value of assets and liabilities that are not considered financial instruments. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates and have not been considered.

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16. Consolidating financial information (unaudited)

Consolidating balance sheet

	December 31, 2002
(in thousands)	HECO			HELCO			MECO			HECO Capital Trust I		HECO Capital Trust II		Reclassi- fications and Elimina- tions					HECO Consolidated
Assets
Utility plant, at cost
Land	$	25,329		$	2,982		$	3,585		$	—	$	—	$	—				$	31,896
Plant and equipment		2,022,987			565,920			595,911			—		—		—					3,184,818
Less accumulated depreciation		(872,332	)		(255,473	)		(240,149	)		—		—		—					(1,367,954	)
Plant acquisition adjustment, net		—			—			302			—		—		—					302
Construction in progress		63,246			93,428			7,626			—		—		—					164,300
Net utility plant		1,239,230			406,857			367,275			—		—		—					2,013,362
Investment in wholly owned subsidiaries, at equity		355,869			—			—			—		—		(355,869	)	[2	]		—
Current assets
Cash and equivalents		9			4			1,713			—		—		—					1,726
Advances to affiliates		14,900			—			23,000			51,546		51,546		(140,992	)	[1	]		—
Customer accounts receivable, net		61,384			13,979			11,750			—		—		—					87,113
Accrued unbilled revenues, net		41,272			10,701			8,125			—		—		—					60,098
Other accounts receivable, net		2,582			411			462			—		—		(1,242	)	[1	]		2,213
Fuel oil stock, at average cost		25,701			3,446			6,502			—		—		—					35,649
Materials & supplies, at average cost		9,076			2,248			8,126			—		—		—					19,450
Prepayments and other		61,108			9,457			5,045			—		—		—					75,610
Total current assets		216,032			40,246			64,723			51,546		51,546		(142,234	)				281,859
Other assets
Regulatory assets		74,946			16,557			14,065			—		—		—					105,568
Unamortized debt expense		8,952			1,915			2,487			—		—		—					13,354
Long-term receivables and other		15,540			3,406			3,297			—		—		—					22,243
Total other assets		99,438			21,878			19,849			—		—		—					141,165
	$	1,910,569		$	468,981		$	451,847		$	51,546	$	51,546	$	(498,103	)			$	2,436,386
Capitalization and liabilities
Capitalization
Common stock equity	$	923,256		$	171,404		$	181,373		$	1,546	$	1,546	$	(355,869	)	[2	]	$	923,256
Cumulative preferred stock–not subject to mandatory redemption		22,293			7,000			5,000			—		—		—					34,293
HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO & HECO-guaranteed debentures		—			—			—			50,000		50,000		—					100,000
Long-term debt, net		495,689			140,993			171,680			—		—		(103,092	)	[1	]		705,270
Total capitalization		1,441,238			319,397			358,053			51,546		51,546		(458,961	)				1,762,819
Current liabilities
Short-term borrowings-affiliate		28,600			14,900			—			—		—		(37,900	)	[1	]		5,600
Accounts payable		41,594			10,462			7,936			—		—		—					59,992
Interest and preferred dividends payable		7,537			1,598			2,435			—		—		(38	)	[1	]		11,532
Taxes accrued		48,274			14,898			15,961			—		—		—					79,133
Other		20,998			3,679			4,547			—		—		(1,204	)	[1	]		28,020
Total current liabilities		147,003			45,537			30,879			—		—		(39,142	)				184,277
Deferred credits and other liabilities
Deferred income taxes		132,159			14,479			11,729			—		—		—					158,367
Unamortized tax credits		28,430			8,471			11,084			—		—		—					47,985
Other		23,441			26,809			14,594			—		—		—					64,844
Total deferred credits and other liabilities		184,030			49,759			37,407			—		—		—					271,196
Contributions in aid of construction		138,298			54,288			25,508			—		—		—					218,094
	$	1,910,569		$	468,981		$	451,847		$	51,546	$	51,546	$	(498,103	)			$	2,436,386

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Consolidating balance sheet

	December 31, 2001
(in thousands)	HECO			HELCO			MECO			HECO Capital Trust I		HECO Capital Trust II		Reclassi- fications and Elimina- tions					HECO Consolidated
Assets
Utility plant, at cost
Land	$	25,369		$	2,752		$	3,568		$	—	$	—	$	—				$	31,689
Plant and equipment		1,943,378			550,671			574,205			—		—		—					3,068,254
Less accumulated depreciation		(810,187	)		(238,962	)		(217,183	)		—		—		—					(1,266,332	)
Plant acquisition adjustment, net		—			—			354			—		—		—					354
Construction in progress		70,501			85,913			14,144			—		—		—					170,558
Net utility plant		1,229,061			400,374			375,088			—		—		—					2,004,523
Investment in wholly owned subsidiaries, at equity		341,186			—			—			—		—		(341,186	)	[2	]		—
Current assets
Cash and equivalents		9			1,282			567			—		—		—					1,858
Advances to affiliates		12,600			—			7,000			51,546		51,546		(122,692	)	[1	]		—
Customer accounts receivable, net		56,227			13,644			12,001			—		—		—					81,872
Accrued unbilled revenues, net		35,072			8,855			8,696			—		—		—					52,623
Other accounts receivable, net		2,537			497			352			—		—		(734	)	[1	]		2,652
Fuel oil stock, at average cost		15,840			3,007			5,593			—		—		—					24,440
Materials & supplies, at average cost		9,168			1,982			8,552			—		—		—					19,702
Prepayments and other		43,326			7,028			3,390			—		—		—					53,744
Total current assets		174,779			36,295			46,151			51,546		51,546		(123,426	)				236,891
Other assets
Regulatory assets		76,153			18,376			16,847			—		—		—					111,376
Unamortized debt expense		7,756			2,040			2,647			—		—		—					12,443
Long-term receivables and other		17,119			3,880			3,506			—		—		—					24,505
Total other assets		101,028			24,296			23,000			—		—		—					148,324
	$	1,846,054		$	460,965		$	444,239		$	51,546	$	51,546	$	(464,612	)			$	2,389,738
Capitalization and liabilities
Capitalization
Common stock equity	$	877,154		$	165,655		$	172,439		$	1,546	$	1,546	$	(341,186	)	[2	]	$	877,154
Cumulative preferred stock–not subject to mandatory redemption		22,293			7,000			5,000			—		—		—					34,293
HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO & HECO-guaranteed debentures		—			—			—			50,000		50,000		—					100,000
Long-term debt, net		461,173			140,962			171,631			—		—		(103,092	)	[1	]		670,674
Total capitalization		1,360,620			313,617			349,070			51,546		51,546		(444,278	)				1,682,121
Current liabilities
Long-term debt due within one year		9,595			5,000			—			—		—		—					14,595
Short-term borrowings-affiliate		55,297			12,600			—			—		—		(19,600	)	[1	]		48,297
Accounts payable		34,860			10,108			8,998			—		—		—					53,966
Interest and preferred dividends payable		7,664			1,698			2,433			—		—		(30	)	[1	]		11,765
Taxes accrued		52,216			15,841			18,001			—		—							86,058
Other		23,712			2,852			3,939			—		—		(704	)	[1	]		29,799
Total current liabilities		183,344			48,099			33,371			—		—		(20,334	)				244,480
Deferred credits and other liabilities
Deferred income taxes		123,097			11,984			10,527			—		—		—					145,608
Unamortized tax credits		28,538			8,644			11,330			—		—		—					48,512
Other		15,557			25,309			14,594			—		—		—					55,460
Total deferred credits and other liabilities		167,192			45,937			36,451			—		—		—					249,580
Contributions in aid of construction		134,898			53,312			25,347			—		—		—					213,557
	$	1,846,054		$	460,965		$	444,239		$	51,546	$	51,546	$	(464,612	)			$	2,389,738

50

Consolidating statement of income

	Year ended December 31, 2002
(in thousands)	HECO			HELCO			MECO			HECO Capital Trust I		HECO Capital Trust II		Reclassi- fications and Elimina- tions					HECO Consolidated
Operating revenues	$	868,383		$	192,209		$	192,337		$	—	$	—	$	—				$	1,252,929
Operating expenses
Fuel oil		214,067			31,333			65,195			—		—		—					310,595
Purchased power		261,000			58,058			7,397			—		—		—					326,455
Other operation		83,190			21,697			27,023			—		—		—					131,910
Maintenance		41,411			13,437			11,693			—		—		—					66,541
Depreciation		63,613			19,548			22,263			—		—		—					105,424
Taxes, other than income taxes		83,089			18,424			18,605			—		—		—					120,118
Income taxes		37,380			7,899			11,450			—		—		—					56,729
		783,750			170,396			163,626			—		—		—					1,117,772
Operating income		84,633			21,813			28,711			—		—		—					135,157
Other income
Allowance for equity funds used during construction		3,514			217			223			—		—		—					3,954
Equity in earnings of subsidiaries		30,782			—			—			—		—		(30,782	)	[2	]		—
Other, net		3,172			342			84			4,149		3,763		(8,369	)	[1	]		3,141
		37,468			559			307			4,149		3,763		(39,151	)				7,095
Income before interest and other charges		122,101			22,372			29,018			4,149		3,763		(39,151	)				142,252
Interest and other charges
Interest on long-term debt		24,633			7,269			8,818			—		—		—					40,720
Amortization of net bond premium and expense		1,290			321			403			—		—		—					2,014
Other interest charges		6,535			1,922			1,410			—		—		(8,369	)	[1	]		1,498
Allowance for borrowed funds used during construction		(1,642	)		(118	)		(95	)		—		—		—					(1,855	)
Preferred stock dividends of subsidiaries		—			—			—			—		—		915		[3	]		915
Preferred securities distributions of trust subsidiaries		—			—			—			—		—		7,675		[3	]		7,675
		30,816			9,394			10,536			—		—		221					50,967
Income before preferred stock dividends of HECO		91,285			12,978			18,482			4,149		3,763		(39,372	)				91,285
Preferred stock dividends of HECO		1,080			534			381			4,025		3,650		(8,590	)	[3	]		1,080
Net income for common stock	$	90,205		$	12,444		$	18,101		$	124	$	113	$	(30,782	)			$	90,205

Consolidating statement of retained earnings

	Year ended December 31, 2002
(in thousands)	HECO			HELCO			MECO			HECO Capital Trust I			HECO Capital Trust II			Reclassi- fications and Elimina- tions					HECO Consolidated
Retained earnings, beginning of period	$	495,961		$	65,690		$	78,182		$	—		$	—		$	(143,872	)	[2	]	$	495,961
Net income for common stock		90,205			12,444			18,101			124			113			(30,782	)	[2	]		90,205
Common stock dividends		(44,143	)		(6,720	)		(9,191	)		(124	)		(113	)		16,148		[2	]		(44,143	)
Retained earnings, end of period	$	542,023		$	71,414		$	87,092		$	—		$	—		$	(158,506	)			$	542,023

51

Consolidating statement of income

	Year ended December 31, 2001
(in thousands)	HECO			HELCO			MECO			HECO Capital Trust I		HECO Capital Trust II		Reclassi- fications and Elimina- tions					HECO Consolidated
Operating revenues	$	885,244		$	193,876		$	205,192		$	—	$	—	$	—				$	1,284,312
Operating expenses
Fuel oil		237,394			28,079			81,255			—		—		—					346,728
Purchased power		263,502			69,023			5,319			—		—		—					337,844
Other operation		80,825			19,181			25,559			—		—		—					125,565
Maintenance		39,258			9,444			13,099			—		—		—					61,801
Depreciation		60,799			18,522			21,393			—		—		—					100,714
Taxes, other than income taxes		83,310			18,315			19,269			—		—		—					120,894
Income taxes		35,774			8,362			11,298			—		—		—					55,434
		800,862			170,926			177,192			—		—		—					1,148,980
Operating income		84,382			22,950			28,000			—		—		—					135,332
Other income
Allowance for equity funds used during construction		3,506			286			447			—		—		—					4,239
Equity in earnings of subsidiaries		31,097			—			—			—		—		(31,097	)	[2	]		—
Other, net		3,447			486			210			4,149		3,763		(8,858	)	[1	]		3,197
		38,050			772			657			4,149		3,763		(39,955	)				7,436
Income before interest and other charges		122,432			23,722			28,657			4,149		3,763		(39,955	)				142,768
Interest and other charges
Interest on long-term debt		23,850			7,628			8,818			—		—		—					40,296
Amortization of net bond premium and expense		1,310			346			407			—		—		—					2,063
Other interest charges		9,775			2,411			1,369			—		—		(8,858	)	[1	]		4,697
Allowance for borrowed funds used during construction		(1,883	)		(174	)		(201	)		—		—		—					(2,258	)
Preferred stock dividends of subsidiaries		—			—			—			—		—		915		[3	]		915
Preferred securities distributions of trust subsidiaries		—			—			—			—		—		7,675		[3	]		7,675
		33,052			10,211			10,393			—		—		(268	)				53,388
Income before preferred stock dividends of HECO		89,380			13,511			18,264			4,149		3,763		(39,687	)				89,380
Preferred stock dividends of HECO		1,080			534			381			4,025		3,650		(8,590	)	[3	]		1,080
Net income for common stock	$	88,300		$	12,977		$	17,883		$	124	$	113	$	(31,097	)			$	88,300

Consolidating statement of retained earnings

	Year ended December 31, 2001
(in thousands)	HECO			HELCO			MECO			HECO Capital Trust I			HECO Capital Trust II			Reclassi- fications and Elimina- tions					HECO Consolidated
Retained earnings, beginning of period	$	443,970		$	62,962		$	73,586		$	—		$	—		$	(136,548	)	[2	]	$	443,970
Net income for common stock		88,300			12,977			17,883			124			113			(31,097	)	[2	]		88,300
Common stock dividends		(36,309	)		(10,249	)		(13,287	)		(124	)		(113	)		23,773		[2	]		(36,309	)
Retained earnings, end of period	$	495,961		$	65,690		$	78,182		$	—		$	—		$	(143,872	)			$	495,961

52

Consolidating statement of income

	Year ended December 31, 2000
(in thousands)	HECO			HELCO			MECO			HECO Capital Trust I		HECO Capital Trust II		Reclassi- fications and Elimina- tions					HECO Consolidated
Operating revenues	$	883,414		$	192,918		$	194,303		$	—	$	—	$	—				$	1,270,635
Operating expenses
Fuel oil		236,298			49,439			77,168			—		—		—					362,905
Purchased power		262,764			41,668			6,775			—		—		—					311,207
Other operation		82,743			20,335			20,701			—		—		—					123,779
Maintenance		43,504			9,328			13,237			—		—		—					66,069
Depreciation		59,608			19,341			19,568			—		—		—					98,517
Taxes, other than income taxes		83,169			18,222			18,393			—		—		—					119,784
Income taxes		34,256			9,480			11,477			—		—		—					55,213
		802,342			167,813			167,319			—		—		—					1,137,474
Operating income		81,072			25,105			26,984			—		—		—					133,161
Other income
Allowance for equity funds used during construction		4,245			232			903			—		—		—					5,380
Equity in earnings of subsidiaries		32,985			—			—			—		—		(32,985	)	[2	]		–
Other, net		4,810			736			958			4,149		3,763		(9,861	)	[1	]		4,555
		42,040			968			1,861			4,149		3,763		(42,846	)				9,935
Income before interest and other charges		123,112			26,073			28,845			4,149		3,763		(42,846	)				143,096
Interest and other charges
Interest on long-term debt		23,369			7,621			9,144			—		—		—					40,134
Amortization of net bond premium and expense		1,262			315			361			—		—		—					1,938
Other interest charges		12,459			3,007			1,385			—		—		(9,861	)	[1	]		6,990
Allowance for borrowed funds used during construction		(2,344	)		(139	)		(439	)		—		—		—					(2,922	)
Preferred stock dividends of subsidiaries		—			—			—			—		—		915		[3	]		915
Preferred securities distributions of trust subsidiaries		—			—			—			—		—		7,675		[3	]		7,675
		34,746			10,804			10,451			—		—		(1,271	)				54,730
Income before preferred stock dividends of HECO		88,366			15,269			18,394			4,149		3,763		(41,575	)				88,366
Preferred stock dividends of HECO		1,080			534			381			4,025		3,650		(8,590	)	[3	]		1,080
Net income for common stock	$	87,286		$	14,735		$	18,013		$	124	$	113	$	(32,985	)			$	87,286

Consolidating statement of retained earnings

	Year ended December 31, 2000
(in thousands)	HECO			HELCO			MECO			HECO Capital Trust I			HECO Capital Trust II			Reclassi- fications and Elimina- tions					HECO Consolidated
Retained earnings, beginning of period	$	425,206		$	59,806		$	69,633		$	—		$	—		$	(129,439	)	[2	]	$	425,206
Net income for common stock		87,286			14,735			18,013			124			113			(32,985	)	[2	]		87,286
Common stock dividends		(68,522	)		(11,579	)		(14,060	)		(124	)		(113	)		25,876		[2	]		(68,522	)
Retained earnings, end of period	$	443,970		$	62,962		$	73,586		$	—		$	—		$	(136,548	)			$	443,970

53

Consolidating statement of cash flows

	Year ended December 31, 2002
(in thousands)	HECO			HELCO			MECO			HECO Capital Trust I			HECO Capital Trust II			Reclassi- fications and Elimina- tions					HECO Consolidated
Cash flows from operating activities:
Income before preferred stock dividends of HECO	$	91,285		$	12,978		$	18,482		$	4,149		$	3,763		$	(39,372	)	[2	]	$	91,285
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Equity in earnings		(30,782	)		—			—			—			—			30,782		[2	]		—
Common stock dividends received from subsidiaries		16,148			—			—			—			—			(16,148	)	[2	]		—
Depreciation of property, plant and equipment		63,613			19,548			22,263			—			—			—					105,424
Other amortization		3,949			1,873			5,554			—			—			—					11,376
Deferred income taxes		9,118			2,495			1,205			—			—			—					12,818
Tax credits, net		953			61			17			—			—			—					1,031
Allowance for equity funds used during construction		(3,514	)		(217	)		(223	)		—			—			—					(3,954	)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable.		(5,202	)		(249	)		141			—			—			508		[1	]		(4,802	)
Decrease (increase) in accrued unbilled revenues		(6,200	)		(1,846	)		571			—			—			—					(7,475	)
Increase in fuel oil stock		(9,861	)		(439	)		(909	)		—			—			—					(11,209	)
Decrease (increase) in materials and supplies		92			(266	)		426			—			—			—					252
Decrease (increase) in regulatory assets		112			418			(2,411	)		—			—			—					(1,881	)
Increase (decrease) in accounts payable		6,734			354			(1,062	)		—			—			—					6,026
Decrease in taxes accrued		(3,942	)		(943	)		(2,040	)		—			—			—					(6,925	)
Changes in other assets and liabilities		(25,264	)		(1,220	)		(1,072	)		—			—			7,167		[2	]		(20,389	)
Net cash provided by operating activities		107,239			32,547			40,942			4,149			3,763			(17,063	)				171,577
Cash flows from investing activities:
Capital expenditures		(71,316	)		(27,541	)		(15,701	)		—			—			—					(114,558	)
Contributions in aid of construction		6,042			3,518			1,482			—			—			—					11,042
Advances to affiliates		(2,300	)		—			(16,000	)		—			—			18,300		[1	]		—
Other		56			—			—			—			—			—					56
Net cash used in investing activities		(67,518	)		(24,023	)		(30,219	)		—			—			18,300					(103,460	)
Cash flows from financing activities:
Common stock dividends		(44,143	)		(6,720	)		(9,191	)		(124	)		(113	)		16,148		[2	]		(44,143	)
Preferred stock dividends		(1,080	)		(534	)		(381	)		—			—			915		[2	]		(1,080	)
Preferred securities distributions of trust subsidiaries		—			—			—			(4,025	)		(3,650	)		—					(7,675	)
Proceeds from issuance of long-term debt		35,275			—			—			—			—			—					35,275
Repayment of long-term debt		—			(5,000	)		—			—			—			—					(5,000	)
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		(26,697	)		2,300			—			—			—			(18,300	)	[1	]		(42,697	)
Other		(3,076	)		152			(5	)		—			—			—					(2,929	)
Net cash used in financing activities		(39,721	)		(9,802	)		(9,577	)		(4,149	)		(3,763	)		(1,237	)				(68,249	)
Net increase (decrease) in cash and equivalents		—			(1,278	)		1,146			—			—			—					(132	)
Cash and equivalents, beginning of period		9			1,282			567			—			—			—					1,858
Cash and equivalents, end of period	$	9		$	4		$	1,713		$	—		$	—		$	—				$	1,726

54

Consolidating statement of cash flows

	Year ended December 31, 2001
(in thousands)	HECO			HELCO			MECO			HECO Capital Trust I			HECO Capital Trust II			Reclassi- fications and Elimina- tions					HECO Consolidated
Cash flows from operating activities:
Income before preferred stock dividends of HECO	$	89,380		$	13,511		$	18,264		$	4,149		$	3,763		$	(39,687	)	[2	]	$	89,380
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Equity in earnings		(31,097	)		—			—			—			—			31,097		[2	]		—
Common stock dividends received from subsidiaries		23,773			—			—			—			—			(23,773	)	[2	]		—
Depreciation of property, plant and equipment		60,799			18,522			21,393			—			—			—					100,714
Other amortization		5,157			2,054			5,529			—			—			—					12,740
Deferred income taxes		6,471			1,448			638			—			—			—					8,557
Tax credits, net		1,429			(95	)		1,142			—			—			—					2,476
Allowance for equity funds used during construction		(3,506	)		(286	)		(447	)		—			—			—					(4,239	)
Changes in assets and liabilities:
Decrease in accounts receivable.		6,031			1,801			918			—			—			698		[1	]		9,448
Decrease in accrued unbilled revenues		9,376			1,289			732			—			—			—					11,397
Decrease in fuel oil stock		8,336			432			3,916			—			—			—					12,684
Decrease (increase) in materials and supplies		(2,210	)		383			(1,088	)		—			—			—					(2,915	)
Increase in regulatory assets		(1,212	)		(255	)		(2,569	)		—			—			—					(4,036	)
Decrease in accounts payable		(16,389	)		(38	)		(1,305	)		—			—			—					(17,732	)
Increase in taxes accrued		6,122			269			1,481			—			—			—					7,872
Changes in other assets and liabilities		(29,548	)		(2,373	)		(2,653	)		—			—			6,977		[2	]		(27,597	)
Net cash provided by operating activities		132,912			36,662			45,951			4,149			3,763			(24,688	)				198,749
Cash flows from investing activities:
Capital expenditures		(69,353	)		(20,503	)		(25,684	)		—			—			—					(115,540	)
Contributions in aid of construction		4,343			4,279			2,336			—			—			—					10,958
Advances to affiliates		9,200			—			(7,000	)		—			—			(2,200	)	[1	]		—
Net cash used in investing activities		(55,810	)		(16,224	)		(30,348	)		—			—			(2,200	)				(104,582	)
Cash flows from financing activities:
Common stock dividends		(36,309	)		(10,249	)		(13,287	)		(124	)		(113	)		23,773		[2	]		(36,309	)
Preferred stock dividends		(1,080	)		(534	)		(381	)		—			—			915		[2	]		(1,080	)
Preferred securities distributions of trust subsidiaries		—			—			—			(4,025	)		(3,650	)		—					(7,675	)
Proceeds from issuance of long-term debt		17,336			—			—			—			—			—					17,336
Net decrease in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		(54,869	)		(7,700	)		(1,500	)		—			—			2,200		[1	]		(61,869	)
Repayment of other short-term borrowings		(3,000	)		—			—			—			—			—					(3,000	)
Other		(569	)		(677	)		—			—			—			—					(1,246	)
Net cash used in financing activities		(78,491	)		(19,160	)		(15,168	)		(4,149	)		(3,763	)		26,888					(93,843	)
Net increase (decrease) in cash and equivalents		(1,389	)		1,278			435			—			—			—					324
Cash and equivalents, beginning of period		1,398			4			132			—			—			—					1,534
Cash and equivalents, end of period	$	9		$	1,282		$	567		$	—		$	—		$	—				$	1,858

55

Consolidating statement of cash flows

	Year ended December 31, 2000
(in thousands)	HECO			HELCO			MECO			HECO Capital Trust I			HECO Capital Trust II			Reclassi- fications and Elimina- tions					HECO Consolidated
Cash flows from operating activities:
Income before preferred stock dividends of HECO	$	88,366		$	15,269		$	18,394		$	4,149		$	3,763		$	(41,575	)	[2	]	$	88,366
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Equity in earnings		(32,985	)		—			—			—			—			32,985		[2	]		—
Common stock dividends received from subsidiaries		25,876			—			—			—			—			(25,876	)	[2	]		—
Depreciation of property, plant and equipment		59,608			19,341			19,568			—			—			—					98,517
Other amortization		4,835			1,335			2,638			—			—			—					8,808
Deferred income taxes		5,297			122			542			—			—			—					5,961
Tax credits, net		997			(28	)		13														982
Allowance for equity funds used during construction		(4,245	)		(232	)		(903	)		—			—			—					(5,380	)
Changes in assets and liabilities:
Increase in accounts receivable.		(17,865	)		(2,867	)		(3,128	)		—			—			828		[1	]		(23,032	)
Increase in accrued unbilled revenues		(6,994	)		(1,220	)		(1,976	)		—			—			—					(10,190	)
Decrease (increase) in fuel oil stock		262			171			(2,603	)		—			—			—					(2,170	)
Decrease in materials and supplies		2,138			830			291			—			—			—					3,259
Increase in regulatory assets		(2,595	)		(696	)		(2,457	)		—			—			—					(5,748	)
Increase in accounts payable		14,591			3,169			1,822			—			—			—					19,582
Increase in taxes accrued		8,218			2,367			1,066			—			—			—					11,651
Changes in other assets and liabilities		(25,528	)		79			(2,558	)		—			—			6,847		[2	]		(21,160	)
Net cash provided by operating activities		119,976			37,640			30,709			4,149			3,763			(26,791	)				169,446
Cash flows from investing activities:
Capital expenditures		(78,786	)		(22,791	)		(28,512	)		—			—			—					(130,089	)
Contributions in aid of construction		3,773			3,289			1,422			—			—			—					8,484
Advances to affiliates		4,400			—			8,400			—			—			(12,800	)	[1	]		—
Payments on notes receivable		—			138			—			—			—			—					138
Net cash used in investing activities		(70,613	)		(19,364	)		(18,690	)		—			—			(12,800	)				(121,467	)
Cash flows from financing activities:
Common stock dividends		(68,522	)		(11,579	)		(14,060	)		(124	)		(113	)		25,876		[2	]		(68,522	)
Preferred stock dividends		(1,080	)		(534	)		(381	)		—			—			915		[2	]		(1,080	)
Preferred securities distributions of trust subsidiaries		—			—			—			(4,025	)		(3,650	)		—					(7,675	)
Proceeds from issuance of long-term debt		67,081			91			20,335			—			—			—					87,507
Repayment of long-term debt		(46,000	)		—			(20,000	)		—			—			—					(66,000	)
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		(5,247	)		(5,900	)		1,500			—			—			12,800		[1	]		3,153
Proceeds from other short-term borrowings		57,499			—			—			—			—			—					57,499
Repayment of other short-term borrowings		(55,682	)		—			—			—			—			—					(55,682	)
Other		2,947			(548	)		(10	)		—			—			—					2,389
Net cash used in financing activities		(49,004	)		(18,470	)		(12,616	)		(4,149	)		(3,763	)		39,591					(48,411	)
Net increase (decrease) in cash and equivalents		359			(194	)		(597	)		—			—			—					(432	)
Cash and equivalents, beginning of period		1,039			198			729			—			—			—					1,966
Cash and equivalents, end of period	$	1,398		$	4		$	132		$	—		$	—		$	—				$	1,534

56

Explanation of reclassifications and eliminations on consolidating schedules

[1] Eliminations of intercompany receivables and payables and other intercompany transactions.

[2] Elimination of investment in subsidiaries, carried at equity.

[3] Reclassification of preferred stock dividends of Hawaii Electric Light Company, Inc. and Maui Electric Company, Limited and of preferred securities distributions of HECO Capital Trust I and HECO Capital Trust II for financial statement presentation.

HECO has not provided separate financial statements and other disclosures concerning HELCO and MECO because management has concluded that such financial statements and other information are not material to holders of the 1997 and 1998 junior deferrable debentures issued by HELCO and MECO to HECO Capital Trust I and HECO Capital Trust II, which debentures have been fully and unconditionally guaranteed by HECO.

17. Consolidated quarterly financial information (unaudited)

Selected quarterly consolidated financial information of the Company for 2002 and 2001 follows:

	Quarters ended								Year ended
2002	March 31		June 30		Sept. 30		Dec. 31		Dec. 31
(in thousands)
Operating revenues	$	277,333	$	306,616	$	332,453	$	336,527	$	1,252,929
Operating income		31,921		35,082		36,512		31,642		135,157
Net income for common stock		20,359		23,850		25,610		20,386		90,205
	Quarters ended								Year ended
2001	March 31		June 30		Sept. 30		Dec. 31		Dec. 31
(in thousands)
Operating revenues	$	317,293	$	312,455	$	340,231	$	314,333	$	1,284,312
Operating income		33,457		34,627		37,526		29,722		135,332
Net income for common stock		21,425		22,716		25,695		18,464		88,300

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

57

Directors and Executive Officers

HAWAIIAN ELECTRIC COMPANY, INC.
DIRECTORS
Robert F. Clarke, 60, 1990	James K. Scott, 51, 1999
T. Michael May, 56, 1995	Anne M. Takabuki, 46, 1997 [1]
Shirley J. Daniel, 49, 2002 [1]	Barry K. Taniguchi, 55, 2001 [1]
Diane J. Plotts, 67, 1991 [1]	Jeffrey N. Watanabe, 60, 1999
[1] Audit committee member.
Note: Year indicates first year elected or appointed. All directors serve one year terms.
OFFICERS
Robert F. Clarke	Chris M. Shirai
Chairman of the Board	Vice President-Energy Delivery
T. Michael May	Thomas C. Simmons
President and Chief Executive Officer	Vice President-Power Supply
Robert A. Alm	Richard A. von Gnechten
Senior Vice President-Public Affairs	Financial Vice President
Thomas L. Joaquin	Patricia U. Wong
Senior Vice President-Operations	Vice President-Corporate Excellence
Karl E. Stahlkopf	Lorie Ann K. Nagata
Senior Vice President-Energy Solutions and Chief Technology     Officer	Treasurer Ernest T. Shiraki
William A. Bonnet	Controller
Vice President-Government & Community Affairs	Molly M. Egged
Jackie Mahi Erickson	Secretary
Vice President-Customer Operations & General Counsel
Charles M. Freedman
Vice President-Corporate Relations

HAWAII ELECTRIC LIGHT COMPANY, INC.
DIRECTORS	ADVISORY BOARD MEMBERS
T. Michael May	T. Michael May, Chairman
Robert F. Clarke	Carol R. Ignacio
Warren H. W. Lee	Warren H. W. Lee
	Barry K. Taniguchi
	Thomas P. Whittemore
	Donald K. Yamada
OFFICERS
T. Michael May	Lorie Ann K. Nagata
Chairman of the Board	Treasurer
Warren H. W. Lee	Molly M. Egged
President	Secretary
Richard A. von Gnechten
Financial Vice President
William A. Bonnet
Vice President

MAUI ELECTRIC COMPANY, LIMITED
DIRECTORS	ADVISORY BOARD MEMBERS
T. Michael May	T. Michael May, Chairman
Robert F. Clarke	Gladys C. Baisa
Edward L. Reinhardt	B. Martin Luna
	Boyd P. Mossman
	Edward L. Reinhardt
	Anne M. Takabuki
OFFICERS
T. Michael May	Lorie Ann K. Nagata
Chairman of the Board	Treasurer
Edward L. Reinhardt	Molly M. Egged
President	Secretary
Richard A. von Gnechten
Financial Vice President
William A. Bonnet
Vice President

Information provided as of February 12, 2003

59

EX-99.3

HEI Exhibit 99.3

AMENDMENT 2002-3

TO THE

HAWAIIAN ELECTRIC INDUSTRIES RETIREMENT SAVINGS PLAN

In accordance with Section 8.1 of the Hawaiian Electric Industries Retirement Savings Plan (the “Plan”), the Plan is hereby amended as follows:

1. Effective January 1, 2003, Section 1.1(a) of the Plan is amended and restated in its entirety to read as follows:

(a) Nonunion Employees. A nonunion Eligible Employee who first performs an Hour of Service on or after January 1, 2003, shall become eligible to participate as of the date he or she first performs an Hour of Service. A nonunion Eligible Employee who is actively employed on January 1, 2003, and who has not become a Participant prior to such date under the Plan’s prior eligibility rules, shall be eligible to participate as of January 1, 2003. A nonunion Eligible Employee who became a Participant prior to January 1, 2003, shall continue as a Participant.

2. Effective January 1, 2002, Section 1.1(c) of the Plan is amended and restated in its entirety to read as follows:

(c) Salary Reduction Elections. An Eligible Employee who has met the requirements for participation in Section 1.1(a) or 1.1(b) becomes a Participant by making a salary reduction election. A salary reduction election is an election by the Participant to forego taxable cash compensation in return for a tax-deferred, employer contribution of equal amount to the Participant’s Account in the Plan. A Participant’s salary reduction election becomes effective as soon as practicable following its completion and submission in accordance with procedures established by the Administrative Committee, but only with respect to amounts that are not currently available to the Participant at the time the election is made.

A Participant may amend or revoke a salary reduction election for any reason, such changes to take effect prospectively. If a Participant voluntarily terminates a salary reduction election, the Participant may resume salary reduction contributions by making and submitting a new election in accordance with procedures established by the Administrative Committee. A Participating Employer, the PIC, or the Administrative Committee may also revoke or amend a Participant’s salary reduction election to prevent the Participant from exceeding one of the maximum limitations described in Article III or in the event of a conflict between the salary reduction election and other payroll deductions authorized by the Participant or required by law. The Administrative Committee may adopt and modify rules and procedures for salary reduction elections.

This section supersedes Section 2 of Amendment 2002-2 to the Plan.

3. Effective January 1, 2002, Section 2.3 of the Plan is amended by revising and restating the last sentence of the fourth paragraph thereof to read as follows:

For the 2001 Plan Year and all Plan Years thereafter, HEI Power Corp. shall not make a HEIDI contribution for any Highly Compensated Employee for any Plan Year.

4. Effective July 1, 2002, Section 2.4 of the Plan is amended and restated in its entirety to read as follows:

Section 2.4 Rollover Contributions

(a) Direct Rollovers. With the consent of the Administrative Committee, a Participant or an Eligible Employee (whether or not a Participant) may make a “direct rollover” to the Plan of an eligible rollover distribution from: (i) a retirement plan qualified under Section 401(a) of the Code; (ii) an annuity plan described in Section 403(a) of the Code; (iii) an individual retirement account or individual retirement annuity described in Section 408 of the Code; (iv) an eligible Section 457(b) deferred compensation plan that is established and maintained by a State, political subdivision of a State, or any agency or instrumentality of a State or political subdivision of a State; or (v) an annuity contract described in Section 403(b) of the Code.

A “direct rollover” is a direct payment of an eligible rollover distribution by any reasonable means from the trustee or annuity provider of the former plan or arrangement to the Trustee of this Plan. The Administrative Committee may adopt reasonable standards and procedures for determining whether a proposed rollover is permissible under this Section and the applicable provision of the Code.

(b) Other Rollovers. The Administrative Committee may consider traditional rollovers by Eligible Employees. To protect the tax-qualified status of the Plan, the Administrative Committee may ask the Eligible Employee to provide an opinion of counsel or other evidence to establish that the requirements for a rollover distribution have been satisfied.

(c) After-Tax Rollovers from Employer Plans. The Plan may accept direct rollovers of after-tax amounts from retirement plans qualified under Section 401(a) of the Code. The Trustee shall separately account for such after-tax amounts.

This Section supersedes Section 4 of Amendment 2002-2.

5. Effective January 1, 2003, Section 4.3 of the Plan, as amended by Amendment 2002-2, is further amended by revising and restating subsection (f)(vi) thereof to read as follows:

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(vi) Number of Loans. Participants may have up to two loans outstanding, without restriction on the use of the loan proceeds, provided the maximum loan amount is not exceeded. Under no circumstances shall the Administrative Committee or the Trustee conduct the loan program in a manner which is more favorable to Participants who are HCEs than to other Participants.

6. Effective January 1, 2002, Section 6.7 of the Plan is amended and restated in its entirety to read as follows:

Section 6.7 Eligible Rollover Distributions

Notwithstanding any provision of the Plan to the contrary, a Participant, surviving spouse, or Alternate Payee may elect, at the time and in the manner prescribed by the Administrative Committee, to have any portion of an “eligible rollover distribution” paid in a “direct rollover.” The Administrative Committee or the Trustee shall include a notice describing the payee’s right to make a direct rollover and describing certain tax consequences that will follow if a direct rollover is not effected (a “402(f) Notice”). The IRS has published a model 402(f) Notice.

An “eligible rollover distribution” is any distribution of all or any portion of the balance to the credit of the distributee, except that an eligible rollover distribution does not include: any distribution that is one of a series of substantially equal periodic payments (not less frequently than annually) made for the life (or life expectancy) of the distributee or the joint lives (or joint life expectancies) of the distributee and the distributee’s designated Beneficiary, or for a specified period of ten years or more; any distribution to the extent such distribution is required under section 401(a)(9) of the Code; the portion of any distribution that is not includible in gross income (determined without regard to the exclusion for net unrealized appreciation with respect to employer securities); and any hardship distribution described in Section 401(k)(2)(B)(i)(IV) of the Code.

A “direct rollover” is a payment from the Trustee directly to the trustee of one of the following (provided it accepts direct rollovers): (i) a defined contribution retirement plan qualified under Section 401(a) of the Code; (ii) an annuity plan described in Section 403(a) of the Code; (iii) an individual retirement account or individual retirement annuity described in Section 408 of the Code; (iv) an eligible Section 457(b) deferred compensation plan that is established and maintained by a State, political subdivision of a State, or any agency or instrumentality of a State or political subdivision of a State, and that agrees to account separately for amounts rolled over to such plan; or (v) an annuity contract described in Section 403(b) of the Code.

A direct rollover may be made by a Participant, an Alternate Payee who is the spouse or former spouse of a Participant, or by a Beneficiary who is the

3

surviving spouse of a Participant. Other Alternate Payees and Beneficiaries may not make direct rollovers.

This Section supersedes Section 17 of Amendment 2002-2.

7. Effective January 1, 2002, Section 10.7 of the Plan (the definition of “Compensation”), as amended by Amendment 2002-2, is further amended by adding the following new paragraph at the end thereof:

For purposes of this Section, effective for all Plan Years beginning on or after January 1, 1998, amounts treated as elective deferrals under Section 125 of the Code (elective cafeteria plan contributions) shall include any amounts not available to a Participant in cash in lieu of group health coverage because the Participant is unable to certify in accordance with the Hawaii Prepaid Healthcare Act that he or she has other health coverage. An amount will be treated as an elective deferral under Section 125 and this paragraph only if the Participating Employers do not request or collect information regarding the Participant’s other health coverage as part of the enrollment process for the health plan.

8. Effective January 1, 2003, Section 10.29 of the Plan (the definition of “Year of Eligibility Service”) is deleted in its entirety.

TO RECORD the adoption of these amendments to the Plan, the Hawaiian Electric Industries, Inc. Pension Investment Committee has caused this document to be executed this 23rd day of December, 2002.

HAWAIIAN ELECTRIC INDUSTRIES, INC. PENSION INVESTMENT COMMITTEE
By	/s/ Robert F. Clarke
	Its member
By	/s/ Peter C. Lewis
	Its member

4