8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

Date of Report: February 26, 2004

Exact Name of Registrant as Specified in Its Charter	Commission File Number	I.R.S. Employer Identification No.
Hawaiian Electric Industries, Inc.	1-8503	99-0208097
Hawaiian Electric Company, Inc.	1-4955	99-0040500

State of Hawaii

(State or other jurisdiction of incorporation)

900 Richards Street, Honolulu, Hawaii 96813

(Address of principal executive offices and zip code)

Registrant’s telephone number, including area code:

(808) 543-5662 - Hawaiian Electric Industries, Inc. (HEI)

(808) 543-7771 - Hawaiian Electric Company, Inc. (HECO)

None

(Former name or former address, if changed since last report.)

Item 7. Financial Statements and Exhibits.

(c) Exhibits.

HEI Exhibit 13	HEI’s 2003 Annual Report to Shareholders
HEI Exhibit 32.1	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)
HEI Exhibit 32.2	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)
HECO Exhibit 32.3	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)
HECO Exhibit 32.4	Written Statement Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002 of Richard A. von Gnechten (HECO Chief Financial Officer)
HECO Exhibit 99	HECO’s Consolidated 2003 Financial Statements

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SIGNATURES

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

HAWAIIAN ELECTRIC INDUSTRIES, INC.	HAWAIIAN ELECTRIC COMPANY, INC.
(Registrant)	(Registrant)
/s/ Eric K. Yeaman	/s/ Richard A. von Gnechten
Eric K. Yeaman Financial Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer of HEI)	Richard A. von Gnechten Financial Vice President (Principal Financial Officer of HECO)
Date: February 26, 2004	Date: February 26, 2004

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EX-13

HEI Exhibit 13

Hawaiian Electric Industries, Inc.

2003 Annual Report to Shareholders

Appendix A

Hawaiian Electric Industries, Inc.

2003 Annual Report to Shareholders

Contents
2	Forward-Looking Statements
3	Selected Financial Data
4	Management’s Discussion and Analysis of Financial Condition and Results of Operations
35	Quantitative and Qualitative Disclosures about Market Risk
39	Independent Auditors’ Report
40	Consolidated Financial Statements
89	Directors and Executive Officers
90	Shareholder Information

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Forward-Looking Statements

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

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

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

• the effects of weather and natural disasters;

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

• the timing and extent of changes in interest rates;

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

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

• demand for services and market acceptance risks;

• increasing competition in the electric utility and banking industries;

• capacity and supply constraints or difficulties;

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

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

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

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

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

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

• the effects of changes in accounting principles applicable to HEI, HECO and their subsidiaries, including the possible effects of applying new accounting principles applicable to variable interest entities (VIEs) to power purchase arrangements with independent power producers;

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

• the results of financing efforts;

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

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

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

• the risks of suffering losses that are uninsured; and

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

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

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Selected Financial Data

Hawaiian Electric Industries, Inc. and Subsidiaries

Years ended December 31	2003			2002			2001			2000			1999
(dollars in thousands, except per share amounts)
Results of operations
Revenues	$	1,781,316		$	1,653,701		$	1,727,277		$	1,732,311		$	1,518,826
Net income (loss)
Continuing operations	$	118,048		$	118,217		$	107,746		$	109,336		$	96,426
Discontinued operations		(3,870	)		—			(24,041	)		(63,592	)		421
	$	114,178		$	118,217		$	83,705		$	45,744		$	96,847
Basic earnings (loss) per common share
Continuing operations	$	3.16		$	3.26		$	3.19		$	3.36		$	3.00
Discontinued operations		(0.10	)		—			(0.71	)		(1.95	)		0.01
	$	3.06		$	3.26		$	2.48		$	1.41		$	3.01
Diluted earnings per common share	$	3.05		$	3.24		$	2.47		$	1.40		$	3.00
Return on average common equity		10.7	%		12.0	%		9.5	%		5.4	%		11.6	%
Return on average common equity-continuing operations *		11.1	%		12.0	%		12.2	%		13.0	%		11.5	%
Financial position **
Total assets	$	9,201,158		$	8,933,553		$	8,552,041		$	8,532,780		$	8,289,914
Deposit liabilities		4,026,250			3,800,772			3,679,586			3,584,646			3,491,655
Securities sold under agreements to repurchase		831,335			667,247			683,180			596,504			661,215
Advances from Federal Home Loan Bank		1,017,053			1,176,252			1,032,752			1,249,252			1,189,081
Long-term debt, net		1,064,420			1,106,270			1,145,769			1,088,731			977,529
HEI- and HECO-obligated preferred securities of trust subsidiaries		200,000			200,000			200,000			200,000			200,000
Preferred stock of subsidiaries – not subject to mandatory redemption		34,406			34,406			34,406			34,406			34,406
Stockholders’ equity		1,089,031			1,046,300			929,665			839,059			847,586
Common stock
Book value per common share **	$	28.72		$	28.43		$	26.11		$	25.43		$	26.31
Market price per common share
High		48.00			49.00			41.25			37.94			40.50
Low		38.20			34.55			33.56			27.69			28.06
December 31		47.37			43.98			40.28			37.19			28.88
Dividends per common share		2.48			2.48			2.48			2.48			2.48
Dividend payout ratio		81	%		76	%		100	%		176	%		82	%
Dividend payout ratio-continuing operations		78	%		76	%		78	%		74	%		83	%
Market price to book value per common share **		165	%		155	%		154	%		146	%		110	%
Price earnings ratio ***		15.0	x		13.5	x		12.6	x		11.1	x		9.6	x
Common shares outstanding (thousands) **		37,919			36,809			35,600			32,991			32,213
Weighted-average		37,348			36,278			33,754			32,545			32,188
Shareholders ****		34,439			34,901			37,387			38,372			39,970
Employees **		3,197			3,220			3,189			3,126			3,262

* 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 shareholders plus participants in the HEI Dividend Reinvestment and Stock Purchase Plan who are not registered shareholders. At February 11, 2004, HEI had 34,404 registered shareholders 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 HEI’s “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 HEI’s “Notes to Consolidated Financial Statements” and Management’s Discussion and Analysis of Financial Condition and Results of Operations for discussions 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. The general discussion of HEI’s consolidated results should be read in conjunction with the segment discussions that follow.

Overview and strategy

HEI’s strategy is to focus its resources on its two core operating businesses, which provide electric public utility and banking services in Hawaii. The success of this strategy will be heavily influenced by Hawaii’s general economic conditions and tourism. Real gross state product grew by 2.9% in 2003 and is expected to grow by 2.8% in 2004. Management believes an investment in HEI stock currently has a lower risk profile than when other HEI subsidiaries pursued international power projects and had real estate and maritime operations.

In 2003, net income from continuing operations was $118 million, comparable to 2002. Basic earnings per share from continuing operations were $3.16 per share in 2003, down 3% from 2002 due primarily to more shares outstanding. Impacting net income in 2003 compared to 2002 was $16 million higher retirement benefits expense, net of tax benefits, or 44 cents per share, primarily at the utilities, and margin compression at ASB caused by the very low interest rates. Partly offsetting these factors were higher kilowatthour (KWH) sales, ASB’s lower provision for loan losses and gains on sales of securities, a major refinancing of Federal Home Loan Bank advances, lower non-bank interest expense and $6 million of net income in the “other” segment from the settlement of lawsuits, which is not expected to recur in 2004.

HEI’s dividend has been stable at $2.48 per share annually since 1998. The dividend yield was 5.2% as of December 31, 2003. The 2003 cut in the individual income tax rate on dividends increased HEI’s after-tax dividend yield for its individual investors.

The Company’s subsidiaries 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.

Electric utility

The electric utility subsidiaries are vertically integrated and regulated by the Hawaii Public Utilities Commission (PUC). Hawaii has not experienced any of the disaggregation or deregulation that has occurred in the industry on the U. S. mainland over the past several years. Keys to achieving reasonable returns from the electric utilities are containing costs, retaining customers by providing reliable service and maintaining close customer relationships, and receiving rate increases when needed.

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

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

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 retaining customers by maintaining customer satisfaction is a critical component in achieving KWH sales and revenue growth in Hawaii over time. The electric utilities have established

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programs that offer these customers specialized services and energy efficiency audits to help them save on energy costs.

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

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

Net income for HECO and its subsidiaries was $79 million in 2003 compared to $90 million in 2002. A swing of $24 million in retirement benefits expense, from a credit of $10 million in 2002 to an expense of $14 million in 2003, was a primary cause of the decline. Pension expense in 2004 is expected to be $6 million lower than in 2003. KWH sales growth was up 2.4% for the year and growth was particularly strong at 5.1 % for the island of Hawaii. Assuming continuing strength in the U.S. and Hawaii economies, management expects higher KWH sales again in 2004.

Bank

American Savings Bank, F. S. B. (ASB) is Hawaii’s third largest financial institution based on assets. When it was acquired by HEI in 1988, it was a traditional thrift with assets of $1 billion and net income of about $13 million. ASB has grown by both acquisition and internal growth since 1988 and finished 2003 with assets of $6.5 billion and net income of $56 million. ASB has been undergoing a major transition to become 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 and fee income while minimizing loan losses. ASB is diversifying its loan portfolio from single-family home mortgages to higher-yielding, shorter-duration consumer, business and commercial real estate loans. To manage this shift in assets, ASB has hired experienced business and commercial real estate lending personnel and has established an appropriate risk management infrastructure.

2003 was a challenging year for all banks like ASB that experienced significant refinancing of mortgages in their portfolio. Net income was $56 million in 2003, comparable to 2002. The over 40-year low in interest rates caused margin compression as ASB could not further reduce its already low cost of funds, as the yield on assets continued to decline due to the high level of refinancings. In addition, ASB’s expenses increased as it continued its transformation to a full service community bank. It is expected that this increased expense level will continue in 2004. Partly offsetting reductions in net income in 2003 was a reduced provision for loan losses resulting from the improved credit quality of ASB’s loan portfolio due to the strong real estate market in Hawaii. Also adding to net income was increased fee income and gains on security sales.

One of the keys to the long-term profitability of ASB is its ability to increase low-cost core deposits — checking and savings accounts. As of December 31, 2003, core deposits as a percentage of total liabilities were 47% compared to 44% as of December 31, 2002 and 40% as of December 31, 2001.

ASB is in a dispute with the Hawaii State Department of Taxation (DOT) concerning the DOT’s position that dividends from ASB’s real estate investment trust (REIT) are taxable under State law versus ASB’s position that dividends are taxable only in part. As of December 31, 2003, the total franchise taxes not recorded and in dispute could negatively impact net income by $23 million (including interest). Trial is expected to begin in July 2004.

ASB is presently managing the duration of its assets and liabilities in anticipation of higher interest rates in 2004 because of the improving economy. In 2003, ASB restructured nearly $0.4 billion of Federal Home Loan Bank advances, which resulted in lower rate, longer maturity advances. 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 project net interest

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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 and commercial real estate loans; (3) investing in mortgage-related securities with short average lives; (4) taking advantage of the lower interest-rate environment by lengthening the maturities of interest-bearing liabilities; and (5) recently, executing a small amount of derivative transactions (see Note 4 in HEI’s “Notes to Consolidated Financial Statements”).

Economic conditions

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

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

Key non-tourism sectors in Hawaii, particularly the military and residential real estate, are fueling economic growth. After remaining relatively stable over the last five years, the military is showing a growing presence with several key military construction projects slated to begin in 2004, including $3 billion of housing renewal projects, $0.7 billion in construction for an Army Stryker Brigade and over $150 million to prepare for the arrival of eight C-17 cargo planes at Hickam Air Force Base.

In general, the construction industry in Hawaii has been doing well. Private building permits were up 37.8% overall for the year through November 2003 compared with same period in 2002, and were also up in all categories—residential (up 24.0%), commercial and industrial (up 110.7%) and additions and alterations (up 28.0%). Local economists anticipate 7% growth in construction in 2003 and a 17% increase for 2004. However, in February 2004, workers in the concrete business went on strike, causing a slowdown in construction in Hawaii.

Although interest rates have been fluctuating recently, they are still close to historical lows and continue to support real estate activity. In 2003, single-family dwelling and condominium resale volumes on Oahu were up 13% and 28%, respectively, while the December 2003 median sales prices were up 14% and 13%, respectively, compared with December 2002. In December 2003, the median price of a single-family dwelling on Oahu was $399,000 and on Maui was $524,000. While interest rates are expected to stay low in the beginning of 2004, lower inventories may reduce sales activity compared with 2003.

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

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

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Results of Operations

Consolidated

(in millions, except per share amounts)	2003			% change		2002			% change		2001
Revenues	$	1,781		8		$	1,654		(4	)	$	1,727
Operating income		264		(1	)		266		4			256
Income from continuing operations	$	118		—		$	118		10		$	108
Loss from discontinued operations		(4	)	NM			—		NM			(24	)
Net income	$	114		(3	)	$	118		41		$	84
Electric utility	$	79		(13	)	$	90		2		$	88
Bank		56		—			56		16			49
Other		(17	)	39			(28	)	3			(29	)
Income from continuing operations	$	118		—		$	118		10		$	108
Basic earnings (loss) per share
Continuing operations	$	3.16		(3	)	$	3.26		2		$	3.19
Discontinued operations		(0.10	)	NM			—		NM			(0.71	)
	$	3.06		(6	)	$	3.26		31		$	2.48
Dividends per share	$	2.48		—		$	2.48		—		$	2.48
Weighted-average number of common shares outstanding		37.3		3			36.3		7			33.8
Dividend payout ratio		81	%				76	%				100	%
Dividend payout ratio – continuing operations		78	%				76	%				78	%

NM Not meaningful.

•    Shareholder dividends are declared and paid quarterly by HEI at the discretion of HEI’s Board of Directors. HEI and its predecessor company, HECO, have paid dividends continuously since 1901. On January 20, 2004, 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 11, 2004 of $51.65, HEI’s dividend yield was 4.8%. The payout ratio based on net income for 2003, 2002 and 2001 was 81%, 76% and 100% (payout ratio of 78%, 76% and 78% based on income from continuing operations), respectively. HEI’s Board and management believe HEI should achieve a 65% payout ratio before it considers increasing the common stock dividend above its current level.

Pension and other postretirement benefits

For 2003, the retirement benefit plan assets generated a total return of nearly 25% for realized and unrealized net gains of $154 million. In contrast, for 2002, 2001 and 2000, the realized and unrealized net losses on retirement benefit plan assets were $112 million, $96 million and $31 million, respectively. Contributions to the retirement benefit plans totaled $48 million in 2003, compared to contributions of $10 million and $5 million during 2002 and 2001, respectively. Contributions are expected to total $14 million in 2004. As of December 31, 2003 and 2002, the market value of such assets was $822 million and $665 million, respectively.

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

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Years ended December 31	(Estimated) 2004			2003			2002
($ in millions)
Consolidated HEI
AOCI balance, net of tax benefits, December 31		NA		$	(1.4	)	$	(5.2	)
Retirement benefits expense (income), net of income taxes 1	$	7.4			12.1			(4.3	)
Consolidated HECO
AOCI balance, net of tax benefits, December 31		NA			(0.2	)		(0.1	)
Retirement benefits expense (income), net of income taxes 1		4.6			8.4			(6.2	)
ASB
AOCI balance, net of tax benefits, December 31		NA			(0.2	)		(4.1	)
Retirement benefits expense, net of income tax benefits 1		2.0			2.7			1.2
Assumptions
Discount rate, January 1		6.25	%		6.75	%		7.25	%
Expected return on plan assets		9.00	%		9.00	%		10.00	%

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

NA Not available.

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

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 HEI’s “Notes to Consolidated Financial Statements.”

Electric utility

(in millions, except per barrel amounts and number of employees)	2003			% change		2002			% change		2001
Revenues 1	$	1,397		11		$	1,257		(2	)	$	1,289
Expenses
Fuel oil		389		25			311		(10	)		347
Purchased power		368		13			326		(3	)		338
Other		463		9			425		4			410
Operating income		177		(9	)		195		1			194
Allowance for funds used during construction		6		6			6		(11	)		6
Net income		79		(13	)		90		2			88
Return on average common equity		8.5	%				10.0	%				10.4	%
Average price per barrel of fuel oil 1	$	36.23		25		$	29.10		(13	)	$	33.49
Kilowatthour sales		9,775		2			9,544		2			9,370
Number of employees (at December 31)		1,862		(2	)		1,894		(2	)		1,930

¹ The rate schedules 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 2003, the electric utilities’ revenues increased by 11%, or $140 million, from 2002 primarily due to higher energy prices ($111 million), a 2.4% increase in KWH sales of electricity ($32 million) and higher demand-side management (DSM) lost margins and shareholder incentives ($4 million), partly offset by lower DSM program and

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

Operating income was $18 million lower than 2002 mainly due to higher other expenses, primarily higher retirement benefit expenses.

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

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

“Other operation” expense increased 18% primarily due to higher retirement benefits expense and environmental expenses (including higher emission fees). Pension and other postretirement benefit costs, net of amounts capitalized, for the electric utilities swung $24 million over 2002 ($14 million expense in 2003 versus a $10 million credit in 2002), partly due to revised assumptions (decreasing the discount rate 50 basis points to 6.75% and the long-term rate of return on assets 100 basis points to 9.0% as of December 31, 2002 compared to December 31, 2001). As of December 31, 2003, the discount rate was further reduced to 6.25%, but retirement benefits expense in 2004 is expected to be $6 million lower than 2003 due to the improved performance of plan assets and contributions made in 2003. “Other operation” expense for 2003 also included $3.1 million of charges related to a settlement reached in December 2003 involving the expansion of the existing plant at Keahole on the island of Hawaii (see Note 3 in HEI’s “Notes to Consolidated Financial Statements”), offset by lower DSM and IRP costs. In January 2004, the Department of Health of the State of Hawaii (DOH) announced that it intended to waive 2003 emissions fees; thus, 2003 emissions fees of $1.5 million, which were accrued in 2003, will be reversed in the first quarter of 2004.

•    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 IPP who was able to produce only an average of about 5.6 megawatt (MW) of firm capacity since April 2002 compared to the 30 MW the IPP contracted to provide to HELCO. Other expenses were up 4% due to a 5% increase in “other operation” expense (including $7 million lower retirement benefits income, net of amounts capitalized, primarily due to a 25 basis points lower discount rate and the market performance of plan assets – i.e., $10 million retirement benefits income in 2002 compared to $17 million in 2001), an 8% increase in maintenance expense partly due to the timing and larger scope of generating unit overhauls, a 5% increase in depreciation expense due to additions to plant in service in 2001, partly offset by a 1% decrease in taxes, other than income taxes. Allowance for funds used during construction (AFUDC) for 2002 was 11% lower than 2001 due to the lower base on which AFUDC was calculated. Interest expense decreased 6% from 2001 due to lower short-term borrowings and interest rates.

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Recent rate requests

HEI’s electric utility subsidiaries initiate PUC proceedings from time to time to request electric rate increases to cover rising operating costs (e.g., higher purchased power capacity charges) and the cost of plant and equipment, including the cost of new capital projects to maintain and improve service reliability. As of February 11, 2004, the return on average common equity (ROACE) found by the PUC to be reasonable in the most recent final rate decision for each utility was 11.40% for HECO (decision and order (D&O) issued on December 11, 1995, based on a 1995 test year), 11.50% for Hawaii Electric Light Company, Inc. (HELCO) (D&O issued on February 8, 2001, based on a 2000 test year) and 10.94% for Maui Electric Company, Limited (MECO) (amended D&O issued on April 6, 1999, based on a 1999 test year). For 2003, the actual simple average ROACEs (calculated under the rate-making method and reported to the PUC) for HECO, HELCO and MECO were 9.20%, 6.61% and 10.08%, respectively. HELCO’s actual ROACE for 2003 of 6.61%, compared to its allowed ROACE of 11.50%, reflects in part HELCO’s decision to discontinue accruing AFUDC, effective December 1, 1998, on its CT-4 and CT-5 generating units that are being installed at the Keahole power plant. The non-accrual of AFUDC (currently estimated at approximately $0.6 million after tax per month) is expected to continue to have a negative impact on HELCO’s ROACE for 2004.

As of February 11, 2004, the return on average rate base (ROR) found by the PUC to be reasonable in the most recent final rate decision for each utility was 9.16% for HECO, 9.14% for HELCO and 8.83% for MECO (D&Os noted above). For 2003, the actual RORs (calculated under the rate-making method) for HECO, HELCO and MECO were 7.95%, 8.65% and 8.79%, respectively.

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

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

Hawaii Electric Light Company, Inc. In early 2001, HELCO received a final D&O from the PUC authorizing an $8.4 million, or 4.9% increase in annual revenues, effective February 15, 2001 and based on an 11.50% ROACE. The D&O included in rate base $7.6 million for pre-air permit facilities needed for the delayed Keahole power plant expansion project that the PUC had also found to be used or useful to support the existing generating units at Keahole. The timing of a future HELCO rate increase request to recover costs relating to the delayed Keahole power plant expansion project, i.e., adding two combustion turbines (CT-4 and CT-5) at Keahole, including the remaining cost of pre-air permit facilities, will depend on future circumstances. See “HELCO power situation” in Note 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 rate case decided by the PUC in February 2001. The rider provides the rates, terms and conditions for obtaining backup and supplemental electric power from the utility when a customer obtains all or part of its electric power from sources other than HELCO.

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Other regulatory matters

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

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

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

Demand-side management programs – agreements with the Consumer Advocate. In October 2001, HECO and the Consumer Advocate finalized agreements, subject to PUC approval, for the continuation of HECO’s three commercial and industrial DSM programs and two residential DSM programs until HECO’s next rate case, which HECO committed to file using a 2003 or 2004 test year. These agreements were in lieu of HECO continuing to seek approval of new 5-year DSM programs. Any DSM programs to be in place after HECO’s next rate case will be determined as part of the case. Under the agreements, HECO will cap the recovery of lost margins and shareholder incentives if such recovery would cause HECO to exceed its current “authorized return on rate base” (i.e. the rate of return on rate base found by the PUC to be reasonable in the most recent rate case for HECO). HECO also agreed it will not pursue the continuation of lost margins recovery and shareholder incentives through a surcharge mechanism in future rate cases. In October 2001, HELCO and MECO reached similar agreements with the Consumer Advocate and filed requests to continue their four existing DSM programs. In November 2001, the PUC issued orders (one of which was later amended) that, subject to certain reporting requirements and other conditions, approved (1) the agreements regarding the temporary continuation of HECO’s five existing DSM programs until HECO’s next rate case and (2) the agreements regarding the temporary continuation of HELCO’s and MECO’s DSM programs until one year after the PUC makes a revenue requirements determination in HECO’s next rate case. Under the orders, however, HELCO and MECO are allowed to recover only lost margins and shareholder incentives accrued through the date that interim rates are established in HECO’s next rate case, but may request to extend the time of such accrual and recovery for up to one additional year. In 2002, MECO’s revenues from shareholder incentives were $0.7 million lower than the amount that would have been recorded if MECO had not agreed to cap such incentives when its authorized ROR was exceeded. Also in 2002, HELCO slightly exceeded its authorized ROR resulting in a reduction of revenues from shareholders incentives for 2002 by $31,000 (recorded in January 2003). In 2002, HECO did not exceed its authorized ROR. In 2003, none of the electric utilities exceeded their respective authorized RORs.

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

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Collective bargaining agreements

Each of the electric utilities reached a new collective bargaining agreement in 2003 with the union which represents approximately 60% of electric utility employees. See “Collective bargaining agreements” in Note 3 in HEI’s “Notes to Consolidated Financial Statements.”

Legislation

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

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

The 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). On December 30, 2003, HELCO signed an approximately 10 MW as-available wind power contract with Hawi Renewable Development. The electric utilities continue to initiate and support many renewable energy research and development projects to help develop these technologies (e.g., photovoltaic projects). They are also conducting integrated resource planning to evaluate the use of more renewables and, in December 2002, HECO formed a nonregulated subsidiary, Renewable Hawaii, Inc. (RHI), to invest in renewable energy projects. In 2003 and 2004, RHI solicited competitive proposals for investment opportunities in projects (1 MW or larger) to supply renewable energy on the islands of Oahu, Maui, Molokai, Lanai and Hawaii. RHI is currently reviewing proposals received. RHI is seeking to take a passive, minority interest in such projects to help stimulate the addition of cost-effective, commercially viable renewable energy generation in the state of Hawaii. Over 8% of consolidated electricity sales for 2003 were from renewable resources (as defined under the renewable portfolio standard law). While the electric utilities thus met the 7% target for 2003 provided for in the 2001 Hawaii legislation, they believe it may be difficult to meet the renewable portfolio standard goals in future years, particularly if sales of electricity increase as projected. Thus, at this time, management cannot predict the impact of this law or of other proposed congressional and Hawaii legislation on the utilities or their customers.

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Bank

(in millions)	2003			% change		2002			% change		2001
Revenues	$	371		(7	)	$	399		(10	)	$	445
Net interest income		190		(2	)		193		4			186
Operating income		93		—			93		13			82
Net income		56		—			56		16			49
Return on average common equity		12.1	%				12.9	%				12.3	%
Interest-earning assets
Average balance 1	$	5,980		4		$	5,745		2		$	5,618
Weighted-average yield		5.23	%	(13	)		6.03	%	(15	)		7.11	%
Interest-bearing liabilities
Average balance 1	$	5,739		5		$	5,488		1		$	5,417
Weighted-average rate		2.15	%	(23	)		2.79	%	(29	)		3.94	%
Interest rate spread		3.08	%	(5	)		3.24	%	2			3.17	%

¹ Calculated using the average daily balances.

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, changes in the value of mortgage servicing rights and expenses from operations.

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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 daily average balances during the year.

	Years ended December 31,
(in thousands)	2003			2002			2001
Loans
Average balances 1	$	3,071,877		$	2,844,341		$	2,963,521
Interest income 2		198,948			203,082			231,858
Weighted-average yield		6.48	%		7.14	%		7.82	%
Mortgage-related securities
Average balances	$	2,707,395		$	2,654,302		$	2,345,630
Interest income		107,496			135,252			152,181
Weighted-average yield		3.97	%		5.10	%		6.49	%
Investments 3
Average balances	$	200,891		$	246,321		$	308,712
Interest and dividend income		6,384			7,896			15,612
Weighted-average yield		3.18	%		3.21	%		5.06	%
Total interest-earning assets
Average balances	$	5,980,163		$	5,744,964		$	5,617,863
Interest and dividend income		312,828			346,230			399,651
Weighted-average yield		5.23	%		6.03	%		7.11	%
Deposits
Average balances	$	3,888,145		$	3,717,553		$	3,638,136
Interest expense		53,808			73,631			116,531
Weighted-average rate		1.38	%		1.98	%		3.20	%
Borrowings
Average balances	$	1,851,258		$	1,770,831		$	1,778,766
Interest expense		69,516			79,251			97,054
Weighted-average rate		3.76	%		4.48	%		5.46	%
Total interest-bearing liabilities
Average balances	$	5,739,403		$	5,488,384		$	5,416,902
Interest expense		123,324			152,882			213,585
Weighted-average rate		2.15	%		2.79	%		3.94	%
Net balance, net interest income and interest rate spread
Net balance	$	240,760		$	256,580		$	200,961
Net interest income		189,504			193,348			186,066
Interest rate spread		3.08	%		3.24	%		3.17	%

¹ Includes nonaccrual loans.

² Includes interest accrued prior to suspension of interest accrual on nonaccrual loans, together with loan fees of $8.6 million, $4.2 million and $3.6 million for 2003, 2002 and 2001, respectively.

³ Includes stock in the FHLB of Seattle.

•    Net interest income before provision for loan losses for 2003 decreased by $3.8 million, or 2.0%, when compared to 2002. Margin compression throughout most of 2003 lowered net interest spread from 3.24% for 2002 to 3.08% in 2003 as the low interest rate environment and significant refinancing activity in the mortgage and

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mortgage-related securities portfolios lowered the yield on earning assets. These lower yields coupled with an inability to lower the interest rates paid on deposits to a commensurate degree reduced interest rate spread. The average loan portfolio balance increased by $227.5 million as the very low interest rate environment and continued strength in the Hawaii real estate market spurred record loan production. ASB’s average residential mortgage portfolio as of year-end 2003 grew by $193.6 million, or 8.5%, over 2002 year-end. ASB increased its average business portfolio by $51.9 million, or 23.5%, during 2003 as its transformation to a full service community bank continued. Average deposit balances grew by $170.6 million as ASB continued to attract core deposits. During 2003, average core deposit balances increased by $268.9 million offset by a decrease in the average balance of term certificates of $98.3 million. The shift in deposit mix lowered the weighted average rate on deposits. In response to pressure on interest rate spreads as a result of the low interest rate environment, ASB restructured a total of $389 million of FHLB advances during 2003. The restructurings involved paying off existing, higher rate FHLB advances with advances that have lower rates and longer maturities. The restructurings resulted in a reduction of interest expense on these FHLB advances of approximately $4.6 million for 2003.

ASB’s provision for loan losses of $3.1 million in 2003 decreased by $6.7 million compared to 2002 as delinquencies continue to decline. A 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 2003. Residential, consumer 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. See “Quantitative and Qualitative Disclosures about Market Risk – Bank.”

Other income for 2003 increased by $5.5 million, or 10.3%, over 2002, principally as a result of net gains on sales of securities totaling $4.1 million compared to a net loss of $0.6 million in 2002, higher fee income from its debit and automated teller machine (ATM) cards resulting from ASB’s expansion of its debit card base and additional ATM services and higher fee income from its deposit liabilities as a result of restructuring of deposit products. Offsetting these increases were lower gains on sale of loans in 2003 compared to 2002 and a lower accrual for the costs of administering delinquent loans in 2002.

General and administrative expenses for 2003 increased by $8.4 million, or 5.9%, over 2002. Compensation and benefits for 2003 was $6.2 million higher than in 2002 primarily due to increased investment in ASB’s workforce to support its transformation initiatives.

•    Net interest income before provision for loan 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. Over 40-year low interest rates spurred 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, residential mortgage loans and high-quality investments are expected to remain ASB’s primary earning assets. 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 were low. 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 effort. 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.”

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ASB experienced some compression in its interest rate spread beginning in September 2002 as the very low short-term interest rates accelerated prepayments and reduced its yield on assets while the cost of funds had essentially reached a floor and could not be reduced much further. At December 31, 2002, ASB was 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 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., 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 (see Note 4 in HEI’s “Notes to Consolidated Financial Statements”).

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 professional services and 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.

•    During 2003, ASB decreased its allowance for loan losses by $1.2 million. As of December 31, 2003 and 2002, ASB’s allowance for loan losses was 1.44% and 1.60%, respectively, of average loans outstanding.

ASB’s nonaccrual and renegotiated loans represented 0.4% and 0.9% of total loans outstanding at December 31, 2003 and 2002, respectively. At December 31, 2003, ASB’s delinquencies were at a nine-year low. See Note 4 in HEI’s “Notes to Consolidated Financial Statements.”

•    In March 1998, ASB formed a subsidiary, ASB Realty Corporation, which elects to be taxed as a REIT. For a discussion of an ongoing dispute with state tax authorities relating to the tax treatment of dividends paid to ASB by ASB Realty Corporation, see Note 9 in HEI’s “Notes to Consolidated Financial Statements.”

Regulation

ASB is subject to extensive regulation, principally by the Office of Thrift Supervision (OTS) and the Federal Deposit Insurance Corporation (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.”

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Other

(in millions)	2003			% change	2002			% change		2001
Revenues 1	$	13		NM	$	(3	)	59		$	(7	)
Operating loss		(6	)	73		(21	)	(8	)		(20	)
Net loss		(17	)	39		(28	)	3			(29	)

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 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, which was sold in July 2003; HEI Properties, Inc. (HEIPI), a company holding passive investments; Hawaiian Electric Industries Capital Trust I and its subsidiary (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; two other inactive subsidiaries, HEI Leasing, Inc. and HEI District Cooling, Inc., which were dissolved in October 2003; HEI and HEI Diversified, Inc. (HEIDI), holding companies; and eliminations of intercompany transactions.

•    HEIII recorded net income of $2.3 million in 2003, $1.5 million in 2002 and $1.5 million in 2001, primarily from leveraged leases.

•    HEIPI recorded net income of $0.1 million in 2003, and net losses of $0.6 million in 2002 and $1.0 million in 2001. HEIPI recorded its share of the net income or losses of Utech Venture Capital Corporation ($0.2 million net income in 2003, $0.3 million net loss in 2002 and $1.2 million net loss in 2001). As of December 31, 2003, HEIPI’s venture capital investments amounted to $3.6 million.

•    Corporate and the other subsidiaries’ revenues in 2003 include $9.3 million from the settlement of lawsuits in the fourth quarter of 2003. 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. There were no writedowns of the income notes in 2003. HEI’s maximum pre-tax exposure to additional financial statement loss as a result of its ownership of the income notes is $4.4 million as of December 31, 2003. See Note 4 of the “Notes to Consolidated Financial Statements.”

HEI Corporate operating, general and administrative expenses (including labor, employee benefits, incentive compensation, charitable contributions, legal fees, consulting, rent, supplies and insurance) were $15.9 million in 2003, $15.6 million in 2002 and $10.5 million in 2001. The increase in expenses from 2001 to 2002 and 2003 was due in part to legal and other expenses incurred in connection with lawsuits and the settlement of lawsuits. Corporate and the other subsidiaries’ net loss was $19.5 million in 2003, $29.2 million in 2002 and $29.6 million in 2001, the majority of which is interest expense. The results for 2003 include net income of $5.7 million from the settlement of lawsuits in the fourth quarter, which is not expected to be recurring. HEI corporate directors and officers insurance premiums for 2004 are expected to be $0.8 million higher than 2003 for the same level of coverage.

•    The “other” segment’s interest expense was $25.0 million in 2003, $28.1 million in 2002 and $31.7 million in 2001. In 2003 and 2002, interest expense for the “other” segment decreased 11% each year compared to the prior year due to lower rates and lower average borrowings. In 2003, $136 million medium-term notes were repaid as they matured primarily with dividends from subsidiaries and the proceeds from the sale of common stock through

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the HEI Dividend Reinvestment and Stock Purchase Plan. In 2002, $59.5 million 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.

Discontinued operations

In 2001, the HEI Board of Directors adopted a plan to exit the international power business and a net loss 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 2003, HEI Power Corp. (HEIPC) wrote down its investment in CEPALCO from $7 million to $2 million and increased its reserve for future expenses by $1 million, resulting in a $4 million after tax reduction of HEI’s net income for 2003. In January 2004, the HEIPC Group signed an agreement for the sale of HEIPC Philippine Development, LLC, the HEIPC Group company that holds its interest in CEPALCO. The sale will be recorded in the first quarter of 2004. See Note 13 of the “Notes to Consolidated Financial Statements.”

Effects of inflation

U.S. inflation, as measured by the U.S. Consumer Price Index, averaged 2.3% in 2003, 1.6% in 2002 and 2.8% in 2001. Hawaii inflation, as measured by the Honolulu Consumer Price Index, averaged 2.3% in 2003, 1.2% in 2002 and 1.2% in 2001. Although the rate of inflation over the past several years has been low, inflation continues to have an impact on 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 and interpretations” in Note 1 of the “Notes to Consolidated Financial Statements.”

Liquidity and capital resources

Consolidated

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

The Company’s total assets were $9.2 billion at December 31, 2003 and $8.9 billion at December 31, 2002.

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	2003				2002
(in millions)
Long-term debt, net	$	1,065	45	%	$	1,106	46	%
HEI- and HECO-obligated preferred securities of trust subsidiaries		200	8			200	9
Preferred stock of subsidiaries		34	1			34	1
Common stock equity		1,089	46			1,046	44
	$	2,388	100	%	$	2,386	100	%

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

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

NR Not rated.

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

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

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

On March 7, 2003, HEI sold $50 million of 4% notes, due March 7, 2008, and $50 million of 5.25% notes, due March 7, 2013 under its registered medium-term note program. The net proceeds from the sales, along with other corporate funds, were ultimately used to repay $100 million of notes (which effectively bore interest at three-month LIBOR plus 376.5 basis points after taking into account two interest rate swaps entered into by HEI with Bank of America) at maturity on April 15, 2003. At December 31, 2003, an additional $200 million principal amount of notes were available for offering by HEI under the registered medium-term note program.

From time to time, HEI and HECO each utilizes short-term debt, principally commercial paper, to support normal operations and for other temporary requirements. From time to time, HECO also borrows short-term from HEI for itself and on behalf of HELCO and MECO, and HECO may borrow from or loan to HELCO and MECO short-term. At December 31, 2003, HECO had $6 million and $26 million of short-term borrowings from HEI and MECO, respectively, and HELCO had $11 million of short-term borrowings from HECO. HEI had no commercial paper borrowings during 2003. HECO had an average outstanding balance of commercial paper for 2003 of $0.4 million and had no commercial paper outstanding at December 31, 2003. Management believes that if 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, 2003, HEI and HECO each maintained bank lines of credit totaling $90 million (all maturing in 2004). These lines of credit are principally maintained by HEI and HECO to support the issuance of commercial paper, but also may be drawn for general corporate purposes. Accordingly, the lines of credit are available for short-term liquidity in the event a rating agency downgrade were to reduce or eliminate access to the commercial paper markets. Lines of credit to HEI totaling $40 million contain provisions for revised pricing in the event of a ratings change (e.g., a ratings downgrade of HEI medium-term notes from BBB/Baa2 to BBB-/Baa3 by S&P and Moody’s, respectively, would result in a 25 to 50 basis points higher interest rate; a ratings upgrade from BBB/Baa2 to BBB+/Baa1 by S&P and Moody’s, respectively, would result in a 20 to 25 basis points lower interest rate). There are no such provisions in the other lines of credit available to HEI and HECO. Further, none of HEI’s or HECO’s line of credit agreements contain “material adverse change” clauses that would affect access to the lines of credit in the

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event of a ratings downgrade or other material adverse events. At December 31, 2003, the lines were unused. To the extent deemed necessary, HEI and HECO anticipate arranging similar lines of credit as existing lines of credit mature. See S&P and Moody’s ratings above and Note 5 in HEI’s “Notes to Consolidated Financial Statements.”

Operating activities provided net cash of $238 million in 2003, $244 million in 2002 and $259 million in 2001. Investing activities used net cash of $322 million in 2003 and $601 million in 2002 and provided net cash of $28 million in 2001. In 2003, net cash was used in investing activities largely due to banking activities (including the purchase of mortgage-related and investment securities and the 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 $123 million in 2003 and $151 million in 2002 and used net cash of $97 million in 2001. In 2003, net cash provided by financing activities was affected by several factors, including net increases in deposits and securities sold under agreements to repurchase 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 advances from the FHLB.

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, in the absence of an unexpected material adverse change in the financial condition of the electric utilities or ASB, 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 debt of other cash obligations. See Note 11 in HEI’s “Notes to Consolidated Financial Statements.”

Forecast HEI consolidated “net cash used in investing activities” (excluding “investing” cash flows from ASB) for 2004 through 2008 consists primarily of the net capital expenditures of HECO and its subsidiaries. In addition to the funds required for the electric utilities’ construction program (see discussion below), approximately $0.2 billion will be required during 2004 through 2008 to repay maturing HEI long-term debt, which is expected to be repaid with the proceeds from the sale of medium-term notes, common stock or other securities. Additional debt and/or equity financing may be required to fund unanticipated expenditures not included in the 2004 through 2008 forecast, such as increases in the costs of or an acceleration of the construction of capital projects of the electric utilities, unbudgeted acquisitions or investments in new businesses, significant increases in retirement benefit funding requirements that might be required if there were significant declines in the market value of pension plan assets or changes in actuarial assumptions and higher tax payments that would result if tax positions taken by the Company do not prevail. Existing debt or trust preferred securities may be refinanced (potentially at more favorable rates) with additional debt or equity financing (or both).

As further explained in Note 8 in HEI’s “Notes to Consolidated Financial Statements,” the Company maintains pension and other postretirement benefit plans. Funding for the pension plans is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under the Employee Retirement Income Security Act of 1974, as amended (ERISA). The Company was not required to make any contributions to the pension plans to meet minimum funding requirements pursuant to ERISA for 2003, but the Company’s Pension Investment Committee chose to make tax deductible contributions in 2003. Contributions to the pension and postretirement benefit plans totaled $48 million in 2003 of which $31 million were made by the electric utilities, $15 million by ASB and $2 million by corporate. Contributions are expected to total $14 million in 2004. 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. Depending on the performance of the assets held in the plans’ trusts and numerous other factors, additional contributions may be required in the future to meet the minimum funding requirements of ERISA or to pay benefits to plan participants. The Company believes it will have adequate access to capital resources to support any necessary funding requirements.

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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	2003				2002
(in millions)
Short-term borrowings	$	6	—	%	$	6	—	%
Long-term debt, net		699	39			705	40
HECO-obligated preferred securities of trust subsidiaries		100	6			100	6
Preferred stock		34	2			34	2
Common stock equity		945	53			923	52
	$	1,784	100	%	$	1,768	100	%

In 2003, the electric utilities’ investing activities used $134 million in cash, primarily for capital expenditures. Financing activities used net cash of $74 million, including $66 million for the payment of common and preferred stock dividends and preferred securities distributions and $6 million for the net repayment of long-term debt. Operating activities provided cash of $206 million.

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

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

The electric utilities’ net capital expenditures for 2004 through 2008 are estimated to total $0.8 billion. HECO’s consolidated cash flows from operating activities (net income, adjusted for noncash income and expense items such as depreciation, amortization and deferred taxes), after the payment of common stock and preferred stock dividends, are expected to provide cash to cover the forecast consolidated net capital expenditures, except for a slight increase in short-term borrowings and in long-term debt from the drawdown of outstanding revenue bond proceeds. Short-term borrowings are expected to fluctuate during this forecast period. Additional debt and/or equity financing may be required for various reasons, including increases in the costs of or an acceleration of the construction of capital projects, unbudgeted acquisitions or investments in new businesses, significant increases in retirement benefit funding requirements that may be required if the market value of pension plan assets does not increase or there are changes in actuarial assumptions and other unanticipated expenditures not included in the 2004 through 2008 forecast. Existing debt or trust preferred securities may be refinanced (potentially at more favorable rates) with additional debt or equity financing (or both). The PUC must approve issuances, if any, of equity and long-term debt securities by HECO, HELCO and MECO.

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Capital expenditures include the costs of projects that are required to meet expected load growth, to improve reliability and to replace and upgrade existing equipment. Net capital expenditures for the five-year period 2004 through 2008 are currently estimated to total $0.8 billion. Approximately 52% of forecast gross capital expenditures (which includes the allowance for funds used during construction and capital expenditures funded by third-party contributions in aid of construction) is for transmission and distribution projects, with the remaining 48% primarily for generation projects and general plant.

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

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

See Note 3 in HEI’s “Notes to Consolidated Financial Statements” for a discussion of fuel and power purchase commitments.

Bank

December 31	2003		% change		2002		% change
(in millions)
Assets	$	6,515	3		$	6,329	5
Available-for-sale investment and mortgage-related securities		2,717	(1	)		2,737	16
Held-to-maturity investment securities		95	6			90	6
Loans receivable, net		3,122	4			2,994	5
Deposit liabilities		4,026	6			3,801	3
Securities sold under agreements to repurchase		831	25			667	(2	)
Advances from FHLB		1,017	(14	)		1,176	14

As of December 31, 2003, ASB was the third largest financial institution in Hawaii based on assets of $6.5 billion and deposits of $4.0 billion.

ASB’s principal sources of liquidity are customer deposits, wholesale borrowings, the sale of mortgage loans into secondary market channels and the maturity and repayment of portfolio loans and mortgage-related securities. ASB’s deposits increased by $225 million during 2003. ASB’s principal sources of borrowings are advances from the FHLB and securities sold under agreements to repurchase from broker/dealers. At December 31, 2003, FHLB borrowings totaled $1.0 billion, representing 16% of assets. ASB is approved to borrow from the FHLB up to 35% of ASB’s assets to the extent it provides qualifying collateral and holds sufficient FHLB stock. At December 31, 2003, ASB’s unused FHLB borrowing capacity was approximately $1.3 billion. At December 31, 2003, securities sold under agreements to repurchase totaled $0.8 billion, representing 13% 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, 2003, 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.

At December 31, 2003, ASB had $5.4 million of loans on nonaccrual status (in general, delinquent more than 90 days), or 0.2% of net loans outstanding, compared to $15.8 million, or 0.5%, at December 31, 2002. At December 31, 2003 and 2002, ASB’s real estate acquired in settlement of loans was $7.9 million and $12.1 million, respectively.

In 2003, net cash of $187 million was used in investing activities largely for the purchase of mortgage-related and investment securities and the origination and purchase of loans, net of repayments and proceeds from sales of securities. Financing activities provided net cash of $202 million due to net increases in deposits and securities sold under agreements to repurchase, partly offset by the payment of common and preferred stock dividends and a net decrease in advances from the FHLB. Operating activities provided cash of $37 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, 2003, ASB was well-capitalized.

Selected contractual obligations and commitments

The following tables present Company-aggregated information about total payments due during the indicated periods under the specified contractual obligations and commercial commitments:

December 31, 2003	Payment due by period
(in millions)	Less than 1 year		1-3 years		4-5 years		After 5 years		Total
Contractual obligations
Deposit liabilities
Commercial checking	$	285	$	—	$	—	$	—	$	285
Other checking		701		—		—		—		701
Savings		1,497		—		—		—		1,497
Money market		343		—		—		—		343
Term certificates		622		444		93		41		1,200
Total deposit liabilities		3,448		444		93		41		4,026
Securities sold under agreements to repurchase		267		334		230		—		831
Advances from Federal Home Loan Bank		124		451		334		108		1,017
Long-term debt, net		1		147		60		856		1,064
HEI- and HECO-obligated preferred securities of trust subsidiaries		—		—		—		200		200
Operating leases, service bureau contract and maintenance agreements		21		20		10		26		77
Fuel oil purchase obligations (estimate based on January 1, 2004 fuel oil prices)		350		—		—		—		350
Purchase power obligations–minimum fixed capacity charges		123		236		234		1,491		2,084
	$	4,334	$	1,632	$	961	$	2,722	$	9,649

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December 31, 2003
(in millions)
Other commercial commitments to ASB customers
Loan commitments and loans in process (primarily expiring in 2004)	$	120
Unused lines and letters of credit		717
	$	837

The tables above do not include other categories of obligations and commitments, such as interest payable, 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. As of December 31, 2003, the fair value of the assets held in trusts to satisfy the obligations of the pension and other postretirement benefit plans exceeded the pension plans’ accumulated benefit obligation and the accumulated postretirement benefit obligation for retirees. Thus, no minimum funding requirements for retirement benefit plans has been included in the tables above.

Certain factors that may affect future results and financial condition

The Company’s results of operations and financial condition can be affected by numerous factors, many of which are beyond its control and could cause future results of operations to differ materially from historical results. The following is a discussion of certain of these factors.

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 generation sector of the electric utility industry has become increasingly competitive in Hawaii. Although competition in the generation sector in Hawaii has been moderated by the scarcity of generation sites, various permitting processes and lack of interconnections to other electric utilities, several IPPs have established power purchase agreements with the electric utilities, and customer self-generation, with or without cogeneration, is a continuing competitive factor.

Recent developments involving distributed generation. Historically, HECO and its subsidiaries have been able to compete by offering customers economic alternatives that, among other things, employ energy efficient electrotechnologies such as the heat pump water heater. However, the number of customer self-generation projects that are being proposed or installed in Hawaii, particularly those involving 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 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, subject to PUC review and approval, to install and operate utility-owned CHP systems at the customers’ sites. Incremental generation from such customer-sited CHP systems, and other DG, is expected to complement traditional central station power, as part of the electric utilities’ plans to serve their forecast load growth. To facilitate the offering of CHP systems, the electric utilities signed a teaming agreement, in

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early 2003, with a manufacturer of packaged CHP systems, but the teaming agreement does not commit the electric utilities to make any CHP system purchases.

In July 2003, three vendors of DG/CHP equipment and services proposed, in an informal complaint to the PUC, that the PUC open a proceeding to investigate the electric utilities’ provision of CHP services and the teaming agreement with another vendor, and to issue rules or orders to govern the terms and conditions under which the electric utilities will be permitted to engage in utility-owned DG at individual customers sites. In August 2003, the electric utilities responded to the informal complaint, and to information requests from the PUC on the CHP demonstration project and teaming agreement. In October 2003, the PUC opened an investigative docket to determine the potential benefits and impact of DG on Hawaii’s electric distribution systems and markets and to develop policies and a framework for DG projects deployed in Hawaii. The PUC also plans to address issues raised in the informal complaint filed by the three vendors of DG/CHP equipment.

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

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

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

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

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

In October 2003, the PUC closed the competition proceeding instituted in 1996. The PUC found that developments in other states indicate that, at best, implementation of retail access would be premature, and determined that no action will be taken to implement retail electric competition in Hawaii at this time. The PUC concluded that projections of any potential benefits of restructuring Hawaii’s electric industry are too speculative and that it has not been sufficiently demonstrated that all consumers in Hawaii would continue to receive adequate, safe, reliable, and efficient energy services at fair and reasonable prices under a restructured market at this time. The PUC indicated it will take a cautious approach to restructuring and will continue to monitor restructuring experiences in other states and at the federal level before proceeding with any major restructuring in Hawaii. The PUC determined that it was in the public interest to work within the current regulatory system to strive to improve

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efficiency within the electric industry, and opened investigative dockets on competitive bidding and DG to move toward a more competitive electric industry environment under cost-based regulation. The stated purpose of the competition bidding investigation is to evaluate competitive bidding as a mechanism for acquiring or building new generating capacity in Hawaii. The PUC stated it would consider related filings on a case-by-case basis pending completion of the docket. The PUC has made the electric utilities in Hawaii and the Consumer Advocate parties to the new proceedings. Motions to intervene or participate were filed by parties in both the DG investigative docket and competitive bidding investigative docket. Management cannot predict the ultimate outcome of these proceedings.

Bank. The banking industry in Hawaii is highly competitive. ASB is the third largest financial institution in Hawaii, based on assets, 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, and national organizations offering financial services. ASB’s main competitors are banks, savings associations, credit unions, mortgage brokers, finance companies and securities brokerage firms. These competitors offer a variety of lending, deposit and investment 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, shorter-duration consumer, business and commercial real estate loans. The origination of consumer, business and commercial real estate loans involves risks and other considerations 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 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 consolidated retirement benefits expense, net of amounts capitalized and income taxes, will be $7 million in 2004 as compared to $12 million in 2003, partly as a result of the performance of HEI’s retirement benefit plans’ assets.

• Volatility in U.S. capital markets may negatively impact the fair values of investment and mortgage-related securities held by ASB and the income notes acquired by HEI in connection with ASB’s disposition of certain trust certificates. As of December 31, 2003, the fair value and carrying value of the investment and mortgage-related securities held by ASB and the income notes held by HEI were $2.8 billion and $12.1 million, respectively.

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. 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 in 2003 as the yields on

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assets declined more rapidly than the cost of funds. This margin compression has continued in early 2004. As of December 31, 2003, the Company had no commercial paper or floating-rate long-term debt outstanding. See “Quantitative and Qualitative Disclosures about Market Risk.”

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 HEI’s “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, 2003, the net assets of the discontinued international power and real estate operations amounted to $12 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.

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. Pursuit of such recoveries, however, is costly and there can be no assurance that the pursuit of any 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 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

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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.

The Honolulu Harbor environmental investigation, described in Note 3 in HEI’s “Notes to Consolidated Financial Statements,” is an ongoing environmental investigation. Although this investigation is expected to entail significant expense over the next several years, management does not believe, based on information available to the Company at this time, that the costs of this investigation or any other contingent liabilities relating to environmental matters will have a material adverse effect on the Company. However, there can be no assurance that a significant environmental liability will not be incurred by the 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 case. At December 31, 2003, HECO and its subsidiaries had recognized $17 million of revenues with respect to interim orders regarding certain integrated resource planning costs, which revenues are subject to refund, with interest, to the extent they exceed the amounts allowed in final orders.

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

The rate schedules of 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

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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. See previous section called “Recent rate requests.”

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 78% of the net energy generated and purchased by HECO and its subsidiaries in 2004 will be generated from the burning of oil. Purchased KWHs provided approximately 39.2% of the total net energy generated and purchased in 2003 compared to 38.0% in 2002 and 39.0% in 2001.

Failure by the electric utilities’ 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 electric utilities 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, Indonesia 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. Two major capital improvement utility projects, the Keahole project and the East Oahu Transmission Project, have encountered opposition and the Keahole project has been seriously delayed (although this project is now scheduled for completion during 2004). See Note 3 in HEI’s “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, 2003, 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:

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• ASB met applicable minimum regulatory capital requirements (noted in parentheses) at December 31, 2003 with a tangible capital ratio of 7.0% (1.5%), a core capital ratio of 7.0% (4.0%) and a total risk-based capital ratio of 15.6% (8.0%).

• ASB met the capital requirements to be generally considered “well-capitalized” (noted in parentheses) at December 31, 2003 with a leverage ratio of 7.0% (5.0%), a Tier-1 risk-based capital ratio of 14.3% (6.0%) and a total risk-based capital ratio of 15.6% (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, 2003, ASB was “well-capitalized” and thus not subject to these restrictions.

Qualified Thrift Lender status. ASB is a “qualified thrift lender” (QTL) and, in order to maintain this status, ASB is required to maintain at least 65% of its assets in “qualified thrift investments,” which include housing-related loans (including mortgage-related securities) 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

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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 sale 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 and related disclosures in conformity with accounting principles generally accepted in the United States of America, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the period reported. Management reviews these estimates and assumptions periodically and reflects the effect of revisions in the period that they are determined to be necessary. Actual results could differ significantly from those estimates.

Material estimates that are particularly susceptible to significant change in the case of the Company include the amounts reported for investment securities; property, plant and equipment; pension and other postretirement benefit obligations; contingencies and litigation; income taxes; regulatory assets and liabilities; electric utility revenues; allowance for loan losses; and reserves for discontinued operations (see “Discontinued operations and asset dispositions” under “Certain factors that may affect future results and financial condition” above).

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

For additional discussion of the Company’s accounting policies, see Note 1 in HEI’s “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 investment and 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 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 investment and mortgage-

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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, 2003, ASB had investment and mortgage-related securities issued by FHLMC, GNMA and FNMA valued at $2.4 billion and private-issue mortgage-related securities valued at $0.3 billion.

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, 2003, HEI had income notes valued at $12.1 million, compared to a valuation of these notes of $8.0 million at December 31, 2002.

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 is charged to accumulated depreciation. Amounts collected from customers for cost of removal (expected to exceed salvage value in the future) are included in regulatory liabilities.

Management believes that the PUC will allow recovery of 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 in Note 3 in HEI’s “Notes to Consolidated Financial Statements” concerning costs recorded in construction in progress for CT-4 and CT-5 at Keahole and the proposed East Oahu Transmission Project.

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

The Company’s reported costs of providing retirement benefits (described in Note 8 in HEI’s “Notes to Consolidated Financial Statements”) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. For example, pension and other postretirement benefit costs are impacted by actual employee demographics (including age and compensation levels), the level of contributions to the plans and earnings on plan assets. Changes made to the provisions of the plans may also impact current and future costs. (No changes were made to the retirement benefit plans’ provisions in 2003, 2002 and 2001 that have had a significant impact on recorded retirement benefit plan amounts.) Costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used.

As a result of the factors listed above, significant portions of pension and other postretirement benefit costs recorded in any period do not reflect the actual benefits provided to plan participants. For 2003 and 2002, the Company recorded other postretirement benefit expense, net of amounts capitalized, of approximately $7 million and $4 million, respectively, in accordance with the provisions of SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” Actual payments of such benefits made to retirees during 2003 and 2002 were $7 million and $6 million, respectively. In accordance with SFAS No. 87, “Employers’ Accounting for Pensions,” changes in pension obligations associated with the factors noted above may not be immediately recognized as pension costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. For 2003 and 2002, the Company recorded non-cash pension expense (income), net of amounts capitalized, of approximately $13 million and $(11) million, respectively, and paid pension benefits of $38 million and $36 million, respectively.

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

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As presented in Note 8 in HEI’s “Notes to Consolidated Financial Statements,” the Company has revised its discount rate as of December 31, 2003 compared to December 31, 2002. The change did not have an impact on reported costs in 2003; however, for future years, this change will have a significant impact. Based upon the revised discount rate (decreased 50 basis points to 6.25%) and plan assets as of December 31, 2003, the Company estimates that retirement benefits expense, net of amounts capitalized and income taxes, will be $7 million in 2004 as compared to $12 million in 2003. Of the $7 million of net retirement benefits expense, it is projected that HECO and its subsidiaries will record an estimated $5 million in 2004 as compared to $8 million in 2003. In determining the retirement benefit costs, assumptions can change from period to period, and such changes could result in material changes to these estimated amounts.

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

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

Actuarial assumption	Change in assumption in basis points		Impact on PBO/APBO			Impact on 2004 net income
($ in millions)
Pension benefits
Discount rate	50		$	(51.9	)	$	1.2
	(50	)		63.7			(3.4	)
Rate of return on plan assets	50			NA			1.8
	(50	)		NA			(1.8	)
Other benefits 1
Discount rate	50			(9.9	)		0.1
	(50	)		10.9			(0.4	)
Health care cost trend rate	100			3.5			(0.2	)
	(100	)		(4.3	)		0.1
Rate of return on plan assets	50			NA			0.2
	(50	)		NA			(0.2	)

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

NA Not applicable.

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

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

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

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. The State of Hawaii Department of Taxation has challenged ASB’s position and, if the state’s position prevails, ASB would suffer adverse state bank franchise tax consequences. See Note 9 of the “Notes to Consolidated Financial Statements” for further information.

Electric utility

Regulatory assets and liabilities. 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, liabilities, revenues 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 liabilities represent amounts collected from customers for costs that are expected to be incurred in the future. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. As of December 31, 2003, regulatory liabilities, net of regulatory assets, amounted to $72 million. Regulatory assets and regulatory liabilities 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 regulatory assets existing as of the last rate case and rates in effect allow the utilities to earn a reasonable rate of return, management believes the regulatory assets as of December 31, 2003 are probable of recovery. This determination assumes continuation of the current political and regulatory climate in Hawaii, and is subject to change in the future.

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

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, 2003, revenues applicable to energy consumed, but not yet billed to the customers, amounted to $60 million.

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

34

objected to the recovery of $2.5 million (before interest) of the $10.3 million of integrated resource planning costs incurred from 1995 through 2002, and the PUC’s decision is pending on this matter.

The rate schedules of 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 and these clauses were continued in the 2001 and 1999 final D&Os in HELCO’s and MECO’s most recent rate cases.

Consolidation of variable interest entities (VIEs). In December 2003, the FASB issued revised FIN No. 46 (FIN No. 46R), “Consolidation of Variable Interest Entities,” which addresses how a business enterprise should evaluate whether it has a controlling financial interest in an entity through means other than voting rights and accordingly should consolidate the entity. The Company is evaluating the impact of applying FIN No. 46R in the first quarter of 2004 to its relationships with IPPs from whom the electric utilities purchase power and has not yet completed this analysis. A possible outcome of the analysis, however, is that HECO (or its subsidiaries, as applicable) may be found to meet the definition of a primary beneficiary of the IPPs, which finding may result in the consolidation of the IPPs in HECO’s consolidated financial statements. The consolidation of IPPs would have a material effect on HECO’s consolidated financial statements, including the recognition of a significant amount of assets and liabilities.

Bank

Allowance for loan losses. See Note 1 in HEI’s “Notes to Consolidated Financial Statements.” At December 31, 2003, ASB’s allowance for loan losses was $44.3 million and ASB had $5.4 million of loans on nonaccrual status (in general, delinquent more than 90 days). In 2003, ASB’s provision for loan losses was $3.1 million. Although management believes the allowance for loan losses is adequate, the actual loan losses, provision for loan losses and allowance for loan losses may be materially different if conditions change (e.g., a significant change in the Hawaii economy occurs).

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, 2003. 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. The Company’s commodity price risk is mitigated by the electric utilities’ energy cost adjustment clauses in their rate schedules. The Company currently has no hedges against its commodity price risk. The Company’s current exposure to foreign currency exchange rate risk is not material.

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.

35

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 change in net interest income (NII) and change in market value of interest-sensitive assets and liabilities resulting from 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. The majority of ASB’s liabilities consist 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 interest rate spread and NII. In a falling interest-rate environment, the opposite happens: the average rate on ASB’s liabilities will tend to decrease faster than the average rate on ASB’s assets, causing an increase in interest rate spread and NII. This volatility in interest rate spread and NII represents one measure of interest rate risk. 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 NII 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 loan originations, such as 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 would typically be 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 continues to build its portfolio of consumer, business and commercial real estate loans, which generally earn higher rates of interest and have maturities shorter than residential real estate loans. However, the origination of consumer, business and commercial real estate loans involves risks and other considerations different from those associated with originating residential real estate loans. For example, credit risk associated with consumer, business and commercial real estate loans is generally higher than for mortgage loans, the sources and level of competition for such loans differ from residential real estate lending and the making of business 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 and commercial real estate loans.

See Note 4 in HEI’s “Notes to Consolidated Financial Statements” for a discussion of the use of rate lock commitments on loans held for sale and forward sale contracts to manage some interest rate risk associated with ASB’s residential loan sale program.

36

Management measures interest-rate risk using simulation analysis with an emphasis on measuring changes in NII and the market value of interest-sensitive assets and liabilities in different interest-rate environments. The simulation analysis is performed using a dedicated asset/liability management software system enhanced with a mortgage prepayment model and a CMO database. The 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.

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.

ASB’s net portfolio value (NPV) ratio is a measure of the economic capitalization of ASB. 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 ASB’s assets grows relative to the value of its liabilities, the NPV ratio will increase. Conversely, if the value of ASB’s liabilities grows relative to the value of its 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. 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.

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

December 31	2003						2002
	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	(5.8	)%	6.30	%	(345	)	1.9	%	7.90	%	(235	)
+200	(3.2	)	7.63		(212	)	3.0		9.15		(110	)
+100	(0.9	)	8.82		(93	)	3.3		10.01		(24	)
Base	—		9.75		—		—		10.25		—
-100	(4.3	)	10.24		49		(5.7	)	10.02		(23	)

37

Management believes that ASB’s interest-rate risk position at December 31, 2003 represents a reasonable level of risk. The December 31, 2003 NII profile is more representative of a “liability sensitive” profile than the December 31, 2002 NII profile. As of December 31, 2003, NII remains essentially flat in the +100 bp scenario, and falls in the +200 and +300 bp scenarios. The reason for the change in profile is the extension in the expected average life of ASB’s mortgage-related assets. There are two primary reasons for the extension: the record low interest rates during the year provided the opportunity for many borrowers to refinance into new mortgages at very low rates, and long-term interest rates as of December 31, 2003 were higher than on December 31, 2002. Higher interest rates reduce the economic incentive for holders of low-rate loans to prepay, resulting in a longer expected average life for these assets. Because ASB’s liabilities tend to have shorter maturities or reprice more frequently than its assets, its net interest margin will tend to decrease as interest rates increase, absent mitigating actions that ASB management may take. The decline in NII in the -100 bp scenario is not typical of a liability sensitive balance sheet, and is a result of the low interest rate environment. Because deposit rates are close to absolute floors, ASB would be unable to lower deposit rates as much as it normally would in a -100 bp scenario. This limits the reduction in interest expense in the -100 bp scenario, causing NII to decrease.

The same factors that affected ASB’s NII sensitivity profile also caused its NPV ratio sensitivity measures to be higher on December 31, 2003 compared to December 31, 2002. The longer expected average life of ASB’s mortgage-related assets caused the NPV ratio to be more sensitive to changes in interest rates.

ASB’s NPV ratio in the base scenario was slightly lower on December 31, 2003 compared to December 31, 2002. While many factors influence the level of the NPV ratio, one of the main reasons for the decline in the NPV ratio was that long-term interest rates were slightly higher on December 31, 2003 than on December 31, 2002. Since the market value of fixed-rate asset instruments declines as interest rates rise, the higher interest rate levels at year-end caused a decline in the calculated value of the fixed-rate assets. Since ASB has more fixed-rate assets than liabilities, the net impact of a rise in interest rates is a decrease in the level of the NPV ratio. The lower NPV ratios in the alternate scenarios as of December 31, 2003 are a function of the lower base case NPV ratio and the increased NPV ratio sensitivity.

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

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. As of December 31, 2003, management believes the Company is exposed to “other than bank” interest rate risk because of their periodic borrowing requirements, the impact of interest rates on the discount rate used to determine retirement benefits expenses and obligations (see sections “Pension and other postretirement benefits” and “Pension and other postretirement benefit obligations” in “Management’s discussion and analysis of financial condition and results of operations” and Note 8 in HEI’s “Notes to consolidated financial statements”) and the possible effect of interest rates on the electric utilities’ allowed rates of return (see “Regulation of electric utility rates”). Other than these exposures, management believes its exposure to “other than bank” interest rate risk is not material.

38

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, 2003 and 2002, and the related consolidated statements of income, changes in stockholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2003. 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, 2003 and 2002, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2003, 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.

/s/ KPMG LLP

Honolulu, Hawaii

February 11, 2004

39

Consolidated Statements of Income

Hawaiian Electric Industries, Inc. and Subsidiaries

Years ended December 31	2003			2002			2001
(in thousands, except per share amounts)
Revenues
Electric utility	$	1,396,685		$	1,257,176		$	1,289,304
Bank		371,320			399,255			444,602
Other		13,311			(2,730	)		(6,629	)
		1,781,316			1,653,701			1,727,277
Expenses
Electric utility		1,220,120			1,062,220			1,095,359
Bank		278,565			306,372			362,503
Other		19,064			18,676			13,242
		1,517,749			1,387,268			1,471,104
Operating income (loss)
Electric utility		176,565			194,956			193,945
Bank		92,755			92,883			82,099
Other		(5,753	)		(21,406	)		(19,871	)
		263,567			266,433			256,173
Interest expense—other than bank		(69,292	)		(72,292	)		(78,726	)
Allowance for borrowed funds used during construction		1,914			1,855			2,258
Preferred stock dividends of subsidiaries		(2,006	)		(2,006	)		(2,006	)
Preferred securities distributions of trust subsidiaries		(16,035	)		(16,035	)		(16,035	)
Allowance for equity funds used during construction		4,267			3,954			4,239
Income from continuing operations before income taxes		182,415			181,909			165,903
Income taxes		64,367			63,692			58,157
Income from continuing operations		118,048			118,217			107,746
Discontinued operations, net of income tax benefits
Loss from operations		—			—			(1,254	)
Net loss on disposals		(3,870	)		—			(22,787	)
Loss from discontinued operations		(3,870	)		—			(24,041	)
Net income	$	114,178		$	118,217		$	83,705
Basic earnings (loss) per common share
Continuing operations	$	3.16		$	3.26		$	3.19
Discontinued operations		(0.10	)		—			(0.71	)
	$	3.06		$	3.26		$	2.48
Diluted earnings (loss) per common share
Continuing operations	$	3.15		$	3.24		$	3.18
Discontinued operations		(0.10	)		—			(0.71	)
	$	3.05		$	3.24		$	2.47
Dividends per common share	$	2.48		$	2.48		$	2.48
Weighted-average number of common shares outstanding		37,348			36,278			33,754
Dilutive effect of stock options and dividend equivalents		139			199			188
Adjusted weighted-average shares		37,487			36,477			33,942

See accompanying “Notes to Consolidated Financial Statements.”

40

Consolidated Balance Sheets

Hawaiian Electric Industries, Inc. and Subsidiaries

December 31				2003					2002
(dollars in thousands)
ASSETS
Cash and equivalents				$	223,310				$	244,525
Federal funds sold					56,678					—
Accounts receivable and unbilled revenues, net					187,716					176,327
Available-for-sale investment and mortgage-related securities					1,787,177					1,960,288
Available-for-sale mortgage-related securities pledged for repurchase agreements					941,571					784,362
Held-to-maturity investment securities (estimated fair value $94,624 and $89,545)					94,624					89,545
Loans receivable, net					3,121,979					2,993,989
Property, plant and equipment, net
Land	$	42,943				$	42,719
Plant and equipment		3,436,352					3,299,850
Construction in progress		200,131					174,122
		3,679,426					3,516,691
Less – accumulated depreciation		(1,367,538	)		2,311,888		(1,274,748	)		2,241,943
Other					382,228					345,002
Goodwill and other intangibles					93,987					97,572
				$	9,201,158				$	8,933,553
LIABILITIES AND STOCKHOLDERS’ EQUITY
Liabilities
Accounts payable				$	132,780				$	134,416
Deposit liabilities					4,026,250					3,800,772
Securities sold under agreements to repurchase					831,335					667,247
Advances from Federal Home Loan Bank					1,017,053					1,176,252
Long-term debt, net					1,064,420					1,106,270
Deferred income taxes					226,590					235,431
Regulatory liabilities					71,882					57,050
Contributions in aid of construction					233,969					218,094
Other					273,442					257,315
					7,877,721					7,652,847
Minority interests 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 10,000,000 shares; issued: none					—					—
Common stock, no par value, authorized 100,000,000 shares; issued and outstanding: 37,918,794 shares and 36,809,319 shares					888,431					839,503
Retained earnings					197,774					176,118
Accumulated other comprehensive income (loss)
Net unrealized gains on securities	$	4,274				$	35,914
Minimum pension liability		(1,448	)		2,826		(5,235	)		30,679
					1,089,031					1,046,300
				$	9,201,158				$	8,933,553

See accompanying “Notes to Consolidated Financial Statements.”

41

Consolidated Statements of Changes in Stockholders’ Equity

Hawaiian Electric Industries, Inc. and Subsidiaries

	Common stock				Retained earnings			Accumulated other comprehensive income (loss)			Total
(in thousands)	Shares	Amount
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	)
Less: 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, net	—		(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, net	—		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
Comprehensive income:
Net income	—		—			114,178			—			114,178
Net unrealized losses on securities:
Net unrealized losses arising during the period, net of tax benefits of $11,538	—		—			—			(29,530	)		(29,530	)
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $1,082	—		—			—			(2,110	)		(2,110	)
Minimum pension liability adjustment, net of taxes of $2,027	—		—			—			3,787			3,787
Comprehensive income (loss)	—		—			114,178			(27,853	)		86,325
Issuance of common stock:
Dividend reinvestment and stock purchase plan	829		36,052			—			—			36,052
Retirement savings and other plans	281		11,433			—			—			11,433
Expenses and other, net	—		1,443			—			—			1,443
Common stock dividends ($2.48 per share)	—		—			(92,522	)		—			(92,522	)
Balance, December 31, 2003	37,919	$	888,431		$	197,774		$	2,826		$	1,089,031

At December 31, 2003, Hawaiian Electric Industries, Inc. (HEI) had reserved a total of 11,756,924 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.

In 1997, the HEI Board of Directors adopted a resolution designating 500,000 shares of Series A Junior Participating Preferred Stock in connection with HEI’s Shareholders Rights Plan, but no shares have been issued.

See accompanying “Notes to Consolidated Financial Statements.”

42

Consolidated Statements of Cash Flows

Hawaiian Electric Industries, Inc. and Subsidiaries

Years ended December 31	2003			2002			2001
(in thousands)
Cash flows from operating activities
Income from continuing operations	$	118,048		$	118,217		$	107,746
Adjustments to reconcile income from continuing operations to net cash provided by operating activities
Depreciation of property, plant and equipment		120,633			115,597			110,425
Other amortization		29,766			25,396			19,119
Provision for loan losses		3,075			9,750			12,500
Writedowns of income notes		—			4,499			14,815
Deferred income taxes		2,838			35,197			382
Allowance for equity funds used during construction		(4,267	)		(3,954	)		(4,239	)
Changes in assets and liabilities, net of effects from the disposal of businesses
Decrease (increase) in accounts receivable and unbilled revenues, net		(11,389	)		(12,203	)		23,932
Increase in deposit for disputed Hawaii franchise taxes		(16,512	)		—			—
Increase (decrease) in accounts payable		(1,636	)		14,566			(5,869	)
Increase (decrease) in taxes accrued		22,045			(38,419	)		(6,761	)
Changes in other assets and liabilities		(24,350	)		(24,265	)		(12,624	)
Net cash provided by operating activities		238,251			244,381			259,426
Cash flows from investing activities
Available-for-sale investment and mortgage-related securities purchased		(2,155,980	)		(1,605,672	)		(1,190,130	)
Principal repayments on available-for-sale investment and mortgage-related securities		1,860,383			1,182,796			605,428
Proceeds from sale of available-for-sale investment and mortgage-related securities		243,406			77,264			788,871
Loans receivable originated and purchased		(1,597,424	)		(1,210,082	)		(1,036,073	)
Principal repayments on loans receivable		1,349,423			949,262			749,378
Proceeds from sale of loans		120,877			110,465			215,888
Proceeds from sale of real estate acquired in settlement of loans		7,728			12,013			9,821
Capital expenditures		(162,891	)		(128,082	)		(126,308	)
Contributions in aid of construction		12,963			11,042			10,958
Other		(624	)		(278	)		(293	)
Net cash provided by (used in) investing activities		(322,139	)		(601,272	)		27,540
Cash flows from financing activities
Net increase in deposit liabilities		225,478			121,186			94,940
Net decrease in short-term borrowings with original maturities of three months or less		—			—			(101,402	)
Repayment of other short-term borrowings		—			—			(3,000	)
Net increase in retail repurchase agreements		13,085			12,180			6,870
Proceeds from securities sold under agreements to repurchase		1,965,575			1,086,531			824,692
Repayments of securities sold under agreements to repurchase		(1,809,945	)		(1,116,148	)		(744,236	)
Proceeds from advances from Federal Home Loan Bank		373,500			350,100			214,100
Principal payments on advances from Federal Home Loan Bank		(532,699	)		(206,600	)		(430,600	)
Proceeds from issuance of long-term debt		167,935			35,275			117,336
Repayment of long-term debt		(210,000	)		(64,500	)		(60,500	)
Preferred securities distributions of trust subsidiaries		(16,035	)		(16,035	)		(16,035	)
Net proceeds from issuance of common stock		29,824			32,451			78,937
Common stock dividends		(75,119	)		(73,412	)		(67,015	)
Other		(8,887	)		(9,742	)		(10,659	)
Net cash provided by (used in) financing activities		122,712			151,286			(96,572	)
Net cash provided by (used in) discontinued operations		(3,361	)		(697	)		47,650
Net increase (decrease) in cash and equivalents and federal funds sold		35,463			(206,302	)		238,044
Cash and equivalents and federal funds sold, January 1		244,525			450,827			212,783
Cash and equivalents and federal funds sold, December 31	$	279,988		$	244,525		$	450,827

See accompanying “Notes to Consolidated Financial Statements.”

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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.

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; property, plant and equipment; pension and other postretirement benefit obligations; contingencies and litigation; income taxes; regulatory assets and liabilities; electric utility revenues; allowance for loan losses; and reserves for discontinued operations.

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 and federal funds sold. 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 of non-affiliates and reverse repurchase agreements and liquid investments (with original maturities of three months or less) to be cash and equivalents. Federal funds sold are excess funds that ASB loans to other banks overnight at the federal funds rate.

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. To determine whether an impairment is other than temporary, the Company considers whether it has the ability and intent to hold the investment until a market price recovery and considers whether evidence indicating the cost of the investment is recoverable outweighs evidence to the contrary. Evidence considered in this assessment includes the magnitude of the impairment, the severity and duration of the impairment, changes in value subsequent to year-end and forecast performance of the investment.

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.

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

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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, 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 is charged to accumulated depreciation. Amounts collected from customers for cost of removal (expected to exceed salvage value in the future) are included in regulatory liabilities.

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 2003, 2002 and 2001.

Retirement benefits. Pension and other postretirement benefit costs/(returns) are charged/(credited) primarily to expense and electric utility plant. The Public Utilities Commission of the State of Hawaii (PUC) requires the Company to fund its pension and postretirement benefit costs. The Company’s policy is to fund pension costs in amounts that will not be less than the minimum funding requirements of the Employee Retirement Income Security Act of 1974 and will not exceed the maximum tax-deductible amounts. The Company generally funds at least the net periodic pension cost as calculated using Statement of Financial Accounting Standards (SFAS) No. 87 during the fiscal year, subject to statutory funding limits and targeted funded status as determined with the consulting actuary. Certain health care and/or life insurance benefits are provided to eligible retired employees and the employees’ beneficiaries and covered dependents. The Company generally funds the net periodic postretirement benefit costs other than pensions as calculated using SFAS No. 106 and the amortization of the regulatory asset for postretirement benefits other than pensions, while maximizing the use of the most tax advantaged funding vehicles, subject to statutory funding limits, cash flow requirements and reviews of the funded status with the consulting actuary.

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.

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.

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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.

At December 31, 2003 and 2002, all options to purchase common stock were included in the computation of diluted EPS. At December 31, 2001, options to purchase 204,000 shares of common stock 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 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 4,650,000 shares of common stock (3,085,336 shares unissued as of December 31, 2003) 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 14,000 shares of restricted stock to date. The restricted stock generally becomes unrestricted three to 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 $112,000 in 2003, $58,000 in 2002 and $8,000 in 2001.

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. In 2001, 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. For 2003 and 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 $2.0 million in 2003 and $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.

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If the accounting provisions of SFAS No. 123 had been applied to the first three quarters of 2002 and the year ended December 31, 2001, the restated or proforma net income and basic and diluted earnings per share would have been:

	Restated quarters ended
(in thousands, except per share amounts)	March 31, 2002			June 30, 2002			September 30, 2002			Proforma 2001
Net income, as reported	$	26,919		$	30,984		$	32,777		$	83,705
Add: Stock option expense included in reported net income, net of tax benefits		131			674			945			1,612
Deduct: Total stock option expense determined under the fair value based method, net of tax benefits		(178	)		(200	)		(210	)		(788	)
Restated or pro forma net income	$	26,872		$	31,458		$	33,512		$	84,529
Earnings per share
Basic – as reported	$	0.75		$	0.86		$	0.90		$	2.48
Basic – restated or pro forma	$	0.75		$	0.87		$	0.92		$	2.50
Diluted – as reported	$	0.75		$	0.85		$	0.89		$	2.47
Diluted – restated or pro forma	$	0.75		$	0.86		$	0.91		$	2.49

Information about HEI’s stock option plan is summarized as follows:

	2003				2002				2001
	Shares		(1)		Shares		(1)		Shares		(1)
Outstanding, January 1	633,025		$	36.62	814,250		$	35.58	813,625		$	35.22
Granted	228,000			40.98	147,000			43.36	170,000			36.29
Exercised	(120,725	)		36.15	(328,225	)		37.07	(162,500	)		34.40
Forfeited or expired	(2,000	)		38.27	—			—	(6,875	)		37.85
Outstanding, December 31	738,300		$	38.04	633,025		$	36.62	814,250		$	35.58
Options exercisable, December 31	295,550		$	35.20	272,775		$	34.93	447,250		$	36.24

(1) Weighted-average exercise price

The weighted-average fair value of each option granted during the year was $8.22, $9.82 and $7.92 (at grant date) in 2003, 2002 and 2001, respectively. The weighted-average assumptions used to estimate fair value include: risk-free interest rate of 3.0%, 4.6% and 4.8%; expected volatility of 18.4%, 17.5% and 18.9%; expected dividend yield of 6.6%, 7.0% and 7.0% for 2003, 2002 and 2001, 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, 2003, unexercised stock options have exercise prices ranging from $29.48 to $43.36 per common share, and a weighted-average remaining contractual life of 7.7 years.

Impairment of long-lived assets and long-lived assets 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.

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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 an obligation of the electric utilities and is settled for other than the carrying amount of the liability, the electric utilities will recognize the difference as a regulatory asset or liability, as the provisions of SFAS No. 143 have no income statement impact for the electric utilities as long as the recovery of the regulatory asset or payment of the regulatory liability is probable. If the obligation is an obligation of a non-electric utility subsidiary and is settled for other than the carrying amount of the liability, such a subsidiary will recognize a gain or loss on settlement. The Company adopted SFAS No. 143 on January 1, 2003 with an immaterial effect on the Company’s financial statements.

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

Costs associated with exit or disposal activities. In June 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),” which required companies to recognize costs associated with exit or disposal activities at the date of a commitment to an exit or disposal plan. SFAS No. 146 replaces EITF Issue No. 94-3. The Company adopted the provisions of SFAS No. 146 on January 1, 2003. Since SFAS No. 146 applies prospectively to exit or disposal activities initiated after December 31, 2002, the adoption of SFAS No. 146 had no effect on the Company’s historical financial statements.

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

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the obligations of any entity or person not included in HEI’s consolidated financial statements, the adoption of these provisions of FIN No. 45 had no effect on HEI’s consolidated historical financial statements.

Consolidation of variable interest entities (VIEs). In December 2003, the FASB issued revised FIN No. 46 (FIN No. 46R), “Consolidation of Variable Interest Entities,” which addresses how a business enterprise should evaluate whether it has a controlling financial interest in an entity through means other than voting rights and accordingly should consolidate the entity. FIN No. 46R replaces FIN No. 46, which was issued in January 2003. The Company was required to apply FIN No. 46 immediately to variable interests in VIEs created after January 31, 2003. For variable interests in VIEs created before February 1, 2003, FIN No. 46 was to be applied no later than the end of the first reporting period ending after December 15, 2003. The disclosures required by FIN No. 46 relating to the income notes purchased by HEI from ASB are included in Note 4, relating to HEI- and HECO-obligated trust preferred securities are included in Note 7 and relating to independent power producers (IPPs) are discussed in Note 3. The Company adopted the provisions (other than the already adopted disclosure provisions) of FIN No. 46 relating to VIEs created before February 1, 2003 as of December 31, 2003 with no effect on the Company’s financial statements.

The Company is evaluating the impact of applying FIN No. 46R in the first quarter of 2004 to the grantor trusts that have issued preferred securities (i.e., existing VIEs in which the Company has variable interests) and has not yet completed this analysis. At this time, it is anticipated that the Company will deconsolidate the trusts that have issued trust preferred securities, as discussed in Note 7, since the Company may not be the primary beneficiary of such trusts. This deconsolidation will result in the Company reflecting $24 million in investment in unconsolidated subsidiaries and $223 million of long-term debt payable to the trusts, rather than $200 million in trust preferred securities in the Consolidated Balance Sheets. Under this treatment, the Company will also record $18 million in interest expense and approximately $2 million in equity in net income of unconsolidated subsidiaries, rather than $16 million in preferred securities distributions of trust subsidiaries in the Consolidated Statements of Income for 2004. Further, the Company is evaluating the impact of applying FIN No. 46R in the first quarter of 2004 to the relationships with IPPs from whom the electric utilities purchase power and has not yet completed this analysis. A possible outcome of the analysis, however, is that HECO (or its subsidiaries, as applicable) may be found to meet the definition of a primary beneficiary of the IPPs, which finding may result in the consolidation of the IPPs in HECO’s consolidated financial statements. The consolidation of IPPs would have a material effect on HECO’s consolidated financial statements, including the recognition of a significant amount of assets and liabilities.

Amendment of SFAS No. 133. In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” which amends and clarifies financial accounting and reporting for derivative instruments and hedging activities and will result in more consistent reporting of contracts as either derivatives or hybrid instruments. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003 (with some exceptions) and for hedging relationships designated after June 30, 2003. The Company adopted the provisions of SFAS No. 149 on July 1, 2003 with no effect on the Company’s historical financial statements. In the fourth quarter of 2003, ASB acquired derivative instruments and engaged in hedging activities (see Note 4).

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

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

Retirement benefits. In December 2003, the FASB issued SFAS No. 132 (revised), “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” which prescribes employers’ disclosures about pension and other postretirement benefit plans, but does not change the measurement or recognition of those plans. SFAS No. 132 (revised) retains and revises the disclosure requirements contained in the original SFAS No. 132 and also requires additional disclosures about the assets, obligations, cash flows, and net periodic benefit cost of defined benefit pension and other postretirement benefit plans. The disclosures required under SFAS No. 132 (revised) for 2003 are included in Note 8.

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 2003 presentation. For example, the accrual for cost of removal (expected to exceed salvage value in the future) of $163 million as of December 31, 2002 has been reclassified from accumulated depreciation to regulatory liabilities.

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

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

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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 meter readings in the beginning of the following month, 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, 2003, customer accounts receivable include unbilled energy revenues of $60 million on a base of annual revenue of $1.4 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 2003 and 2001, HECO and its subsidiaries included $123 million and $114 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense. 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.

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. If a project under construction is delayed for an extended period of time, AFUDC may be stopped.

The weighted-average AFUDC rate was 8.7% in 2003, 2002 and 2001, and reflected quarterly compounding.

Bank

Loans receivable. American Savings Bank, F.S.B. and subsidiaries (ASB) state loans receivable at amortized cost less the allowance for loan losses, loan origination fees (net of direct costs), 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 loans using the level-yield method.

Loan origination fees (net of direct loan origination costs) are deferred and recognized as an adjustment in yield over the estimated life of the loan using the level-yield method. Nonrefundable commitment fees (net of direct loan origination costs, if applicable) received for commitments to originate or purchase loans are deferred and, if the commitment is exercised, recognized as an adjustment of yield over the life of the loan (which is adjusted for prepayments) using the interest method. Nonrefundable commitment fees received for which the commitment expires unexercised are recognized as income upon expiration of the commitment.

Loans held for sale, gain on sale of loans, and mortgage servicing rights. Loans held for sale are stated at the lower of cost or estimated market value on an aggregate basis. Generally, the determination of market value is based on the fair value of the loans. However, the determination of market value for certain commercial real estate loans is based on the fair value of the underlying collateral. A sale is recognized only when the consideration received is other than beneficial interests in the assets sold and control over the assets is transferred irrevocably to the buyer. Gains or losses on sales of loans are recognized at the time of sale and are determined by the difference between the net sales proceeds and the allocated basis of the loans sold.

ASB capitalizes mortgage servicing rights (MSRs) when the related loans are sold with servicing rights retained. The total cost of the mortgage loans sold is allocated to the MSRs and the mortgage loans without the MSRs based on their relative fair values at the date of sale. The MSRs are included as a component of gain on sale of loans. The MSRs are amortized in proportion to and over the estimated period of net servicing income. Such amortization is reflected as a component of fee income on loans serviced for others.

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The MSRs are periodically reviewed for impairment based on their fair value. The fair value of the MSRs, for the purposes of impairment, is measured using a discounted cash flow analysis based on market-adjusted discount rates and anticipated prepayment speeds. Market sources are used to determine prepayment speeds and net cost of servicing per loan.

ASB measures MSR impairment on a disaggregated basis based on certain risk characteristics including loan type and note rate. Impairment losses are recognized through a valuation allowance for each impaired stratum, with any associated provision recorded as a component of loan servicing fees.

Allowance for loan losses. ASB maintains an allowance for loan losses that it believes is adequate to absorb estimated inherent 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 conditions. Adverse changes in any of these factors could result in higher charge-offs and loan provisions.

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, by the lending officer. ASB’s credit review department performs an evaluation of the commercial market and commercial real estate loan portfolios to ensure compliance with the internal risk rating system and timeliness of rating changes. A loan is deemed impaired when it is probable that ASB will be unable to collect all amounts due according to the contractual terms of the loan agreement. The measurement of impairment may be based on (i) the present value of the expected future cash flows of the impaired loan discounted at the loan’s original effective interest rate, (ii) the observable market price of the impaired loan, or (iii) the fair value of the collateral. For all loans secured by real estate, ASB measures impairment by utilizing the fair value of the collateral; for other loans, discounted cash flows are used to measure impairment. If the recorded investment in the loan exceeds the measure of impairment, losses are charged to the provision for loan losses and included in the allowance for loan losses.

For the residential, consumer and homogeneous commercial loans receivable portfolios, 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.

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, September 30, 2002 and September 30, 2003 and will be tested for impairment annually in the fourth quarter using data as of September 30. As of January 1, 2002, September 30, 2002 and September 30, 2003, 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.

For 2001 and prior years, 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, and determined that no change in estimated useful life was required and that there was no impairment of goodwill.

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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:

Years ended December 31	2003		2002		2001
(in thousands, except per share amounts)
Consolidated
Reported net income	$	114,178	$	118,217	$	83,705
Goodwill amortization, net of tax benefits		—		—		3,845
Adjusted net income	$	114,178	$	118,217	$	87,550
Per common share:
Reported basic earnings	$	3.06	$	3.26	$	2.48
Goodwill amortization, net of tax benefits		—		—		0.11
Adjusted basic earnings	$	3.06	$	3.26	$	2.59
Per common share:
Reported diluted earnings	$	3.05	$	3.24	$	2.47
Goodwill amortization, net of tax benefits		—		—		0.11
Adjusted diluted earnings	$	3.05	$	3.24	$	2.58
Bank
Reported net income	$	56,261	$	56,225	$	48,531
Goodwill amortization, net of tax benefits		—		—		3,845
Adjusted net income	$	56,261	$	56,225	$	52,376

Amortized intangible assets.

December 31	2003				2002
(in thousands)	Gross carrying amount		Accumulated amortization		Gross carrying amount		Accumulated amortization
Core deposit intangibles	$	20,276	$	13,471	$	20,276	$	11,741
Mortgage servicing rights		10,637		6,535		9,506		4,239
	$	30,913	$	20,006	$	29,782	$	15,980

In 2003, 2002 and 2001, aggregate amortization expenses were $4.0 million, $3.4 million and $3.0 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 2003 and 2002, mortgage servicing rights acquired were not significant.

The estimated aggregate amortization expense for ASB’s core deposits and mortgage servicing rights for 2004, 2005, 2006, 2007 and 2008 is $3.2 million, $2.9 million, $2.7 million, $2.4 million and $0.6 million, respectively.

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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 on all major islands in Hawaii other than Kauai, and are regulated by the PUC. HECO also owns non-regulated subsidiaries: Renewable Hawaii, Inc. (RHI), which will invest in renewable energy projects; HECO Capital Trust I and HECO Capital Trust II, which are financing entities; and HECO Capital Trust III, which was formed in November 2003 in connection with a possible future financing.

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 and intercompany eliminations.

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(in thousands)	Electric Utility		Bank		Other			Total
2003
Revenues from external customers	$	1,396,683	$	371,320	$	13,313		$	1,781,316
Intersegment revenues (eliminations)		2		—		(2	)		—
Revenues		1,396,685		371,320		13,311			1,781,316
Depreciation and amortization		118,792		30,748		859			150,399
Interest expense		44,341		123,324		24,951			192,616
Profit (loss)*		128,735		87,220		(33,540	)		182,415
Income taxes (benefit)		49,824		30,959		(16,416	)		64,367
Income (loss) from continuing operations		78,911		56,261		(17,124	)		118,048
Capital expenditures		146,964		15,798		129			162,891
Assets (at December 31, 2003, including net assets of discontinued operations)		2,581,256		6,515,208		104,694			9,201,158
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)		2,493,436		6,328,606		111,511			8,933,553
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)		2,423,836		6,011,448		116,757			8,552,041

* 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	2003			2002			2001
(in thousands)
Revenues
Operating revenues	$	1,393,038		$	1,252,929		$	1,284,312
Other—nonregulated		3,647			4,247			4,992
		1,396,685			1,257,176			1,289,304
Expenses
Fuel oil		388,560			310,595			346,728
Purchased power		368,076			326,455			337,844
Other operation		155,531			131,910			125,565
Maintenance		64,621			66,541			61,801
Depreciation		110,560			105,424			100,714
Taxes, other than income taxes		130,677			120,118			120,894
Other—nonregulated		2,095			1,177			1,813
		1,220,120			1,062,220			1,095,359
Operating income from regulated and nonregulated activities		176,565			194,956			193,945
Allowance for equity funds used during construction		4,267			3,954			4,239
Interest and other charges		(52,931	)		(52,822	)		(55,646	)
Allowance for borrowed funds used during construction		1,914			1,855			2,258
Income before income taxes and preferred stock dividends of HECO		129,815			147,943			144,796
Income taxes		49,824			56,658			55,416
Income before preferred stock dividends of HECO		79,991			91,285			89,380
Preferred stock dividends of HECO		1,080			1,080			1,080
Net income for common stock	$	78,911		$	90,205		$	88,300

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Balance sheet data

December 31	2003			2002
(in thousands)
Assets
Utility plant, at cost
Property, plant and equipment	$	3,336,004		$	3,217,016
Less accumulated depreciation		(1,290,929	)		(1,205,336	)
Construction in progress		195,295			164,300
Net utility plant		2,240,370			2,175,980
Other		340,886			317,456
	$	2,581,256		$	2,493,436
Capitalization and liabilities
Common stock equity	$	944,443		$	923,256
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, net		699,420			705,270
Total capitalization		1,778,156			1,762,819
Short-term borrowings from affiliate		6,000			5,600
Deferred income taxes		170,841			158,367
Regulatory liabilities		71,882			57,050
Contributions in aid of construction		233,969			218,094
Other		320,408			291,506
	$	2,581,256		$	2,493,436

Regulatory assets and liabilities. In accordance with SFAS No. 71, HECO and its subsidiaries’ financial statements reflect assets, liabilities, revenues and expenses based on current cost-based rate-making regulations. Their continued accounting under SFAS No. 71 generally requires that rates are established by an independent, third-party regulator; rates are designed to recover the costs of providing service; and it is reasonable to assume that rates can be charged to and collected from customers. Management believes HECO and its subsidiaries’ operations currently satisfy the SFAS No. 71 criteria. If events or circumstances should change so that those criteria are no longer satisfied, the electric utilities expect that the regulatory liabilities, net of regulatory assets, would be credited to income. In the event of unforeseen regulatory actions or other circumstances, however, management believes that a material adverse effect on the Company’s results of operations and financial position may result if regulatory assets have to be charged to expense without an offsetting credit from regulatory liabilities.

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Regulatory liabilities represent costs expected to be incurred in the future (period noted in parenthesis). Regulatory assets represent deferred costs expected to be fully recovered through rates over PUC authorized periods ranging from one to 36 years (period noted in parenthesis). Regulatory assets (liabilities) were as follows:

December 31	2003			2002
(in thousands)
Cost of removal in excess of salvage value (1 to 50 years)	$	(178,424	)	$	(162,618	)
Income taxes, net (1 to 36 years)		66,129			64,278
Postretirement benefits other than pensions (10 years)		16,108			17,897
Unamortized expense and premiums on retired debt and equity issuances (2 to 26 years)		12,148			11,005
Integrated resource planning costs, net (1 year)		2,731			1,965
Vacation earned, but not yet taken (1 year)		4,750			4,776
Other (1 to 5 years)		4,676			5,647
	$	(71,882	)	$	(57,050	)

Cumulative preferred stock. The 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 10% ($135 million), 9% ($119 million) and 10% ($127 million) of their operating revenues from the sale of electricity to various federal government agencies in 2003, 2002 and 2001, respectively.

Commitments and contingencies

Fuel contracts. HECO and its subsidiaries have contractual agreements to purchase minimum quantities of fuel oil and diesel fuel through December 31, 2004 (at prices tied to the market prices of petroleum products in Singapore and Los Angeles). New fuel contracts are currently being negotiated. Based on the average price per barrel at January 1, 2004, the estimated cost of minimum purchases under the fuel supply contracts for 2004 is $350 million. The actual cost of purchases in 2004 could vary substantially from this estimate as a result of changes in market prices, quantities actually purchased and/or other factors. HECO and its subsidiaries purchased $390 million, $317 million and $328 million of fuel under contractual agreements in 2003, 2002 and 2001, respectively.

Power purchase agreements (PPAs). At December 31, 2003, HECO and its subsidiaries had seven PPAs for a total of 534 megawatts (MW) of firm capacity. Of the 534 MW of firm capacity under PPAs, approximately 79% is under PPAs with AES Hawaii, Inc. (since March 1988), Kalaeloa Partners, L.P. (since October 1988) and Hamakua Energy Partners, L.P. (since October 1997). The primary business activities of these IPPs are the generation and sale of power to the electric utilities. Financial information about the size of these IPPs is not currently available. Purchases from all IPPs totaled $368 million, $326 million and $338 million for 2003, 2002 and 2001, respectively. The PUC allows rate recovery for energy and firm capacity payments to IPPs under these agreements. Assuming that each of the agreements remains in place for its current term and the minimum availability criteria in the PPAs are met, aggregate minimum fixed capacity charges are expected to be approximately $123 million in 2004, $118 million each in 2005, 2006 and 2007, $116 million in 2008, and a total of $1.5 billion in the period from 2009 through 2030.

In general, HECO and its subsidiaries base their payments under the PPAs 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.

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Interim increases. At December 31, 2003, HECO and its subsidiaries had recognized $17 million of revenues with respect to interim orders regarding certain integrated resource planning costs, which revenues are subject to refund, with interest, if and to the extent they exceed the amounts allowed in final orders.

HELCO power situation. After several years of opposition to, and resulting delays in, the efforts of HELCO to expand its Keahole power plant site to add new generation, HELCO entered into a conditional settlement agreement in November of 2003 (Settlement Agreement) with all but one of the parties (Waimana Enterprises, Inc. (Waimana), which had actively opposed the project) and with several regulatory agencies. The settlement agreement is intended to permit HELCO to complete the plant expansion, subject to satisfaction of the terms and conditions of the Settlement Agreement, and HELCO is actively engaged in construction activities to install the planned generation. Two 20 MW combustion turbines (CT-4 and CT-5) are currently expected to be ready for initial operation in the second quarter of 2004 and fully operational by the end of 2004.

The following is a summary of the status of HELCO’s efforts to obtain certain of the permits required for the Keahole expansion project and related proceedings that have impeded and delayed HELCO’s efforts to construct the plant, a description of the Settlement Agreement and its implementation to date and a discussion (under “Management’s evaluation; costs incurred”) of the potential financial statement implications of this project.

Historical context. In 1991, HELCO began planning to meet increased electric generation demand forecast for 1994. HELCO’s plans were to install at its Keahole power plant CT-4 and CT-5, followed by an 18 MW heat steam recovery generator (ST-7), at which time these units would be converted to a 56 MW (net) dual-train combined-cycle unit. In January 1994, the PUC approved expenditures for CT-4, which HELCO had planned to install in late 1994. In 1995, the PUC allowed HELCO to pursue construction of and commit expenditures for CT-5 and ST-7, but noted in its decision that such costs are not to be included in rate base until the project is installed and “is used and useful for utility purposes.” The PUC at that time also ordered HELCO to continue negotiating with IPPs that had proposed generating facilities that they claimed would be a substitute for HELCO’s planned expansion of the Keahole plant, stating that the facility to be built should be the one that can be most expeditiously put into service at “allowable cost.”

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

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

The Enserch and HCPC complaints were resolved by HELCO’s entry into PPAs with each of these parties. The PPA with HCPC by its terms expires in December 2004 (subject to early termination or extensions). Due to subsequent developments, including a ruling by the Hawaii Circuit Court for the Third Circuit (Third Circuit Court) that the lease for KCP’s proposed plant site was invalid, HELCO believes that KCP’s proposal for a PPA is not viable.

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

Land use permit amendment and related proceedings. The Third Circuit Court ruled in 1997 that, because the BLNR had failed to render a valid decision on HELCO’s application to amend its land use permit before the statutory deadline in April 1996, HELCO was entitled to use its Keahole site for the expansion project (HELCO’s “default entitlement”). The Third Circuit Court’s 1998 final judgment on this issue was appealed to the Hawaii Supreme Court by several parties. On July 8, 2003, the Hawaii Supreme Court issued its opinion affirming the Third Circuit Court’s final judgment on the basis that the BLNR failed to render the necessary four votes either approving or rejecting HELCO’s application.

While the Hawaii Supreme Court’s July 2003 decision validated the Third Circuit Court’s 1998 final judgment confirming HELCO’s default entitlement, construction of the expansion project had been delayed for much of the intervening period that had followed the 1998 final judgment, first because HELCO had not yet obtained its final air permit and then because of other rulings made by the Third Circuit Court in several related proceedings.

The Third Circuit Court’s 1998 final judgment confirming HELCO’s default entitlement provided that HELCO must comply with the conditions in its application and with the standard land use conditions insofar as those conditions were not inconsistent with the default entitlement. Numerous proceedings were commenced before the Third Circuit Court and the BLNR in which parties opposed to the project claimed that HELCO had not or could not comply with the conditions applicable to its default entitlement. The Third Circuit Court issued a number of rulings in these proceedings which further delayed or otherwise adversely affected HELCO’s ability to construct and efficiently operate CT-4 and CT-5. These rulings have now been, or are expected to be, resolved under the terms of the Settlement Agreement, as follows:

·  Based on a change by the DOH in its interpretation of the noise rules it promulgated under the Hawaii Noise Pollution Act, the Third Circuit Court ruled that a stricter noise standard applied to HELCO’s Keahole plant. HELCO filed a separate complaint for declaratory relief against the DOH seeking the invalidation of the noise rules on constitutional and other grounds. The Third Circuit Court ruled against HELCO in that separate complaint, and HELCO appealed the Third Circuit Court’s final judgment to this effect (Noise Standards Judgment) in August 1999. In the Settlement Agreement, HELCO agrees that the Keahole plant will comply during normal operations with the stricter noise standards and that it will not begin full-time operations of CT-4 and CT-5 until it has installed noise mitigation equipment to meet these standards. In accordance with the Settlement Agreement, on January 6, 2004, the parties filed a stipulation to dismiss HELCO’s appeal of the Noise Standards Judgment.

·  In other litigation in the Third Circuit Court brought by Keahole Defense Coalition (KDC) and two individuals (Individual Plaintiffs), the Third Circuit Court denied plaintiff’s motions made on several grounds to enjoin construction of the Keahole plant and plaintiffs appealed these rulings to the Hawaii Supreme Court in June 2002. Pursuant to the Settlement Agreement, on January 6, 2004, KDC filed a motion in the Hawaii Supreme Court to dismiss this appeal.

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

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

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

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

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

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

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

·  On November 5, 2003, Waimana filed a complaint in the United States District Court for the District of Hawaii in which it sought, among other things, a temporary restraining order enjoining the Third Circuit Court from granting the motion to vacate the November 2002 Final Judgment. The United States District Court denied this motion on November 7, 2003 and dismissed Waimana’s complaint on November 14, 2003.

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

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

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

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

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Since the time construction activities resumed in November 2003, HELCO has laid the groundwork for implementation of many of its commitments under the Settlement Agreement. However, despite the numerous rulings against Waimana described above, it has continued to pursue efforts to stop or delay the Keahole project and to interfere with implementation of the Settlement Agreement, including (a) filing a notice of appeal to the Hawaii Supreme Court of the Third Circuit Court’s November 2003 Final Judgment (vacating the November 2002 Final Judgment), (b) appealing to the Third Circuit Court the BLNR 2003 Construction Period Extension and (c) appealing to the Third Circuit Court the BLNR’s approval, on December 12, 2003, of HELCO’s request for a revocable permit to use brackish well water as the primary source of water for operating the Keahole plant. In January 2004, the Third Circuit Court denied Waimana’s motion to stay the effectiveness of the BLNR 2003 Construction Period Extension, and granted HELCO’s motion (joined in by the BLNR) to dismiss Waimana’s appeal of that extension. In February 2004, the Third Circuit Court denied Waimana’s motion to stay the effectiveness of the revocable permit to use brackish water, and granted HELCO’s motion (joined in by the BLNR) to dismiss Waimana’s appeal of that permit.

Land Use Commission petition. After previously submitting and withdrawing a petition, HELCO submitted to the Hawaii State Land Use Commission (LUC) on November 25, 2003 a new petition to reclassify the Keahole plant site from conservation land use to urban land use. The installation of ST-7, with SCR as contemplated by the Settlement Agreement, is dependent upon this reclassification. In December 2003, Waimana filed a Notice of Intent to Intervene in the LUC proceeding. On February 5, 2004, the LUC issued an order, with which HELCO concurred, that an environmental impact statement (EIS) be prepared in connection with its reclassification petition. Work on the EIS was already in progress before the ruling was issued. The entire reclassification process could take several years.

Management’s evaluation; costs incurred. The probability that HELCO will be allowed to complete the installation of CT-4 and CT-5 during 2004 has been substantially enhanced by the Settlement Agreement, the Third Circuit’s November 2003 Final Judgment, and the decisions of the BLNR to extend the construction deadline by 19 months from December 31, 2003 and to grant to HELCO a revocable permit to use brackish water for the plant. Although additional steps must be completed under the Settlement Agreement to satisfy its remaining conditions and HELCO must obtain the further permits necessary to complete installation of CT-4 and CT-5 (and, eventually ST-7), management believes that the prospects are good that those conditions will be satisfied and that any further necessary permits will be obtained. Nevertheless, Waimana has continued its efforts to stop or delay the construction and there could be further delays in completing construction. In the meantime, HELCO’s management remains concerned with the condition and performance of certain aging generators on the HELCO system, which were intended to be retired or to be operated less frequently once CT-4 and CT-5 were installed, as well as the current operating status of various IPPs, which provide approximately 43% of HELCO’s generating capacity under power purchase agreements. A related 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. HELCO is continuing its efforts to avert power interruptions, but there can be no assurance that power interruptions will not occur.

Based on management’s expectation that the remaining conditions under the Settlement Agreement will be satisfied, HELCO recorded as expenses in November 2003 approximately $3.1 million of legal fees and other costs required to be paid under the Settlement Agreement. If the Settlement Agreement is implemented and ST-7 is installed, HELCO will have incurred approximately $21 million of capital expenditures relating to noise mitigation, visual mitigation and air pollution control at the Keahole power plant site (approximately $8 million for CT-4 and CT-5, approximately $9 million for ST-7, when installed, and approximately $4 million for other existing units). Other miscellaneous incidental expenses may also be incurred.

As of December 31, 2003, HELCO’s costs incurred in its efforts to put CT-4 and CT-5 into service and to support existing units (excluding costs the PUC permitted to be transferred to plant-in-service for pre-air permit facilities) amounted to approximately $84 million, including $32 million for equipment and material purchases, $32 million for planning, engineering, permitting, site development and other costs and $20 million for AFUDC up to November 30, 1998, after which date management decided not to continue to accrue AFUDC in light of the delays

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that had been experienced, even though management believes that it has acted prudently with respect to the Keahole project. Substantial additional costs, currently estimated to be approximately $15 million, will be required in order to complete the installations of CT-4 and CT-5, including the costs necessary to satisfy the requirements of the Settlement Agreement pertaining to those units. HELCO’s plans for ST-7 are pending until it obtains the contemplated reclassification of the Keahole plant site from conservation to urban and necessary permits, which HELCO has agreed to seek promptly. The costs of ST-7 will be higher than originally planned, not only by reason of the change in schedule in its installation, but also by reason of additional costs that will be incurred to satisfy the requirements of the Settlement Agreement.

The recovery of costs relating to CT-4 and CT-5 is subject to the rate-making process governed by the PUC. Management believes no adjustment to costs incurred to put CT-4 and CT-5 into service is required as of December 31, 2003. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HELCO may be required to write off a material portion of the costs incurred in its efforts to put these units into service whether or not CT-4 and CT-5 are installed.

Oahu transmission system. HECO’s power sources are located primarily in West Oahu, but the bulk of HECO’s system load is in the Honolulu/East Oahu area. Accordingly, HECO transmits bulk power to the Honolulu/East Oahu area over two major transmission corridors (Northern and Southern). HECO had planned to construct a part underground/part overhead 138 kilovolt (kV) transmission line from the Kamoku substation to the Pukele substation in order to close the gap between the Southern and Northern corridors and provide a third 138 kV transmission line to the Pukele substation. Construction of the proposed transmission line in its originally proposed location required the BLNR to approve a CDUP for the overhead portion of the line that would have been in conservation district lands. Several community and environmental groups opposed the project, particularly the overhead portion of the line and, in June 2002, the BLNR denied HECO’s request for a CDUP.

HECO continues to believe that the proposed project (the East Oahu Transmission Project) is needed to improve the reliability of the Pukele substation, which serves approximately 16% of Oahu’s electrical load, including Waikiki, and to address future potential line overloads under certain contingencies. In 2003, HECO completed its evaluation of alternative ways to accomplish the project (including using 46 kV transmission lines). As part of its evaluation, HECO conducted a community-based process to obtain public views of the alternatives. In December 2003, HECO filed an application with the PUC requesting approval to commit funds (currently estimated at $55 million) for its revised East Oahu Transmission Project. Six groups and two individuals have sought to intervene in the preceeding.

Subject to PUC approval, the revised project, none of which is in conservation district lands, will be built in two phases. Completion of the first phase, targeted for 2006, will address future potential transmission line overloads in the Northern and Southern corridors and improve the reliability of service to many customers in the Pukele substation service area, including Waikiki. The second phase, projected to take an additional two years to complete, will improve service to additional customers in the Pukele substation service area by minimizing the duration of service interruptions that could occur under certain contingencies.

As of December 31, 2003, the accumulated costs related to the East Oahu Transmission Project amounted to $20 million, including $13 million for planning, engineering and permitting costs and $7 million for AFUDC. These costs are recorded in construction in progress. The recovery of costs relating to the project is subject to the rate-making process administered by the PUC. Management believes no adjustment to project costs incurred is required as of December 31, 2003. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HECO may be required to write off a material portion or all of the project costs incurred in its efforts to put the project into service whether or not it is completed.

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State of Hawaii, ex rel., Bruce R. Knapp, Qui Tam Plaintiff, and Beverly Perry, on behalf of herself and all others similarly situated, Class Plaintiff, vs. The AES Corporation, AES Hawaii, Inc., HECO, and HEI. In April 2002, HECO and HEI were served with an amended complaint filed in the Circuit Court for the First Circuit of Hawaii alleging that the State of Hawaii and HECO’s other customers have been overcharged for electricity as a result of alleged excessive prices in the amended PPA between defendants HECO and AES Hawaii, Inc. (AES Hawaii). AES Hawaii is a subsidiary of The AES Corporation (AES), which guarantees certain obligations of AES Hawaii under the amended PPA.

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

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

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

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

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

On August 25, 2003, the First Circuit Court issued an order dismissing with prejudice the amended complaint, including all of the Plaintiffs’ remaining claims against the defendants for violations under the Hawaii False Claims Act after May 26, 2000. The final judgment was entered on September 17, 2003. On October 15, 2003, plaintiff Beverly J. Perry filed a notice of appeal to the Hawaii Supreme Court and the Intermediate Court of Appeals, on the grounds that the Circuit Court erred in its reliance on the doctrine of primary jurisdiction and the statute of limitations. AES subsequently filed a cross-appeal of the order denying its motion to dismiss the action, which it had filed on February 24, 2003. Plaintiff Perry filed her opening brief on February 9, 2004 and HEI/HECO’s answering brief is due on March 19, 2004.

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

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

Under the terms of the 1999 agreement for the sale of assets of HTB and the stock of YB, HEI and The Old Oahu Tug Service, Inc. (TOOTS, formerly HTB) have specified indemnity obligations, including obligations with respect to the Honolulu Harbor investigation. In April 2003, TOOTS agreed to pay $250,000 (for TOOTS and HEI) to the Participating Parties to fund response activities in the Iwilei Unit of the Honolulu Harbor site, as a one-time cash-out payment in lieu of continuing with further response activities.

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

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

Management developed a preliminary estimate of HECO’s share of costs primarily from 2002 through 2004 for continuing investigative work, remedial activities and monitoring at the Iwilei Unit of approximately $1.1 million (of which $0.25 million has been incurred through December 31, 2003). The $1.1 million estimate was expensed in 2001. Also, individual companies have incurred costs to remediate their facilities which will not be allocated to the Participating Parties. Because (1) the full scope and extent of additional investigative work, remedial activities and monitoring are unknown at this time, (2) the final cost allocation method has not yet been determined and (3) management cannot estimate the costs to be incurred (if any) for the sites other than the Iwilei Unit (including its Honolulu power plant site), the cost estimate may be subject to significant change and additional material investigative and remedial costs may be incurred.

Maalaea Units 12 and 13 notice and finding of violation. On September 5, 2003, MECO received a Notice of Violation (NOV) issued by the Department of Health of the State of Hawaii (DOH) alleging violations of opacity

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conditions in permits issued under the DOH’s Air Pollution Control Law for two generating units at MECO’s Maalaea Power Plant. The NOV ordered MECO to immediately take corrective action to prevent further opacity incidents. The NOV also ordered MECO to pay a penalty of $1.6 million, unless MECO submitted a written request for a hearing. In September 2003, MECO submitted a request for hearing and accrued $1.6 million for the potential penalty. An environmental penalty or a settlement of an environmental penalty is not tax deductible.

On December 23, 2003, the DOH and MECO reached a conditional settlement of the NOV, which is subject to public notice and a comment period of at least 30 days. The settlement consists of a Proposed Consent Order that requires MECO to come into full compliance with the opacity rules for the units by December 31, 2004 and to pay a penalty of approximately $0.8 million to the DOH. If signed, the Proposed Consent Order would resolve all civil liability of MECO to the DOH for all opacity violations from February 1, 1999 to December 31, 2004. The DOH has agreed that it will sign the Proposed Consent Order after the close of the public comment period if it continues to conclude that the settlement is appropriate. The public comment period expires in late February 2004. MECO has made significant progress in reducing the number of opacity exceedances from Maalaea Units 12 and 13 and expects to achieve full compliance with the opacity regulations during the Proposed Consent Order period without having to incur significant additional costs.

Since the settlement is subject to public notice and comment and final action by the DOH, management can provide no assurance that the Consent Order will be approved and executed by the DOH in the form proposed. However, management believes at this time that $0.8 million is the probable penalty amount for the NOV. Accordingly, MECO reduced the initial September 2003 accrual of $1.6 million to $0.8 million in December 2003.

Collective bargaining agreements. On November 7, 2003, members of the International Brotherhood of Electrical Workers (IBEW), AFL-CIO, Local 1260, Unit 8, ratified new collective bargaining and benefit agreements with HECO, HELCO and MECO. Of the electric utilities’ approximately 1,860 employees, about 1,100 are members of IBEW, AFL-CIO, Local 1260, Unit 8, which is the only union representing employees of the Company. The new collective bargaining and benefit agreements cover a four-year term, from November 1, 2003 to October 31, 2007, and provide for non-compounded wage increases (3% on November 1, 2003, 1.5% on November 1, 2004, 1.5% on May 1, 2005, 1.5% on November 1, 2005, 1.5% on May 1, 2006, and 3% on November 1, 2006) and include changes to medical, drug, vision and dental plans and increased employee contributions.

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4 • Bank subsidiary

Selected consolidated financial information

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

Income statement data

Years ended December 31	2003		2002			2001
(in thousands)
Interest and dividend income
Interest and fees on loans	$	198,948	$	203,082		$	231,858
Interest on mortgage-related securities		107,496		135,252			152,181
Interest and dividends on investment securities		6,384		7,896			15,612
		312,828		346,230			399,651
Interest expense
Interest on deposit liabilities		53,808		73,631			116,531
Interest on Federal Home Loan Bank advances		48,280		58,608			68,740
Interest on securities sold under repurchase agreements		21,236		20,643			28,314
		123,324		152,882			213,585
Net interest income		189,504		193,348			186,066
Provision for loan losses		3,075		9,750			12,500
Net interest income after provision for loan losses		186,429		183,598			173,566
Other income
Fees from other financial services		22,817		21,254			17,194
Fee income on deposit liabilities		16,971		15,734			9,401
Fee income on other financial products		9,920		10,063			8,451
Fee income on loans serviced for others, net		155		(164	)		2,458
Gain (loss) on sale of securities		4,085		(640	)		8,044
Writedown of investment		—		—			(6,164	)
Other income		4,544		6,778			5,567
		58,492		53,025			44,951
General and administrative expenses
Compensation and employee benefits		65,805		59,594			51,932
Occupancy and equipment		30,546		30,086			28,638
Data processing		10,668		11,167			10,408
Professional services		8,670		9,376			5,504
Office supplies, printing and postage		4,850		4,746			5,323
Communication		4,072		3,465			3,213
Marketing		3,973		3,967			3,626
Amortization of goodwill and core deposit intangibles		1,730		1,731			6,706
Other		21,852		19,608			21,068
		152,166		143,740			136,418
Income before minority interests and income taxes		92,755		92,883			82,099
Minority interests		124		173			213
Income taxes		30,959		31,074			27,944
Income before preferred stock dividends		61,672		61,636			53,942
Preferred stock dividends		5,411		5,411			5,411
Net income for common stock	$	56,261	$	56,225		$	48,531

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Balance sheet data

December 31	2003			2002
(in thousands)
Assets
Cash and equivalents	$	209,598		$	214,704
Federal funds sold		56,678			—
Available-for-sale investment and mortgage-related securities		1,775,053			1,952,317
Available-for-sale mortgage-related securities pledged for repurchase agreements		941,571			784,362
Held-to-maturity investment securities		94,624			89,545
Loans receivable, net		3,121,979			2,993,989
Other		221,718			196,117
Goodwill and other intangibles		93,987			97,572
	$	6,515,208		$	6,328,606
Liabilities and stockholders’ equity
Deposit liabilities–noninterest bearing	$	469,272		$	369,961
Deposit liabilities–interest bearing		3,556,978			3,430,811
Securities sold under agreements to repurchase		831,335			667,247
Advances from Federal Home Loan Bank		1,017,053			1,176,252
Other		97,429			137,888
		5,972,067			5,782,159
Minority interests		3,417			3,417
Preferred stock		75,000			75,000
Common stock		244,568			243,628
Retained earnings		221,109			192,692
Accumulated other comprehensive income (loss)		(953	)		31,710
		464,724			468,030
	$	6,515,208		$	6,328,606

Investment and mortgage-related securities

December 31, 2003
										Gross unrealized losses
($ in thousands)	Amortized cost		Gross unrealized gains		Gross unrealized losses			Estimated fair value		Less than 12 months						12 months or longer
										Count	Fair Value		Amount			Count	Fair Value		Amount
Available-for-sale
Investment securities-federal agency obligation	$	49,833	$	172	$	—		$	50,005
Mortgage-related securities:
FNMA		1,377,300		16,317		(9,297	)		1,384,320	45	$	668,981	$	(9,297	)	—	$	—	$	—
FHLMC		754,514		3,376		(4,098	)		753,792	24		447,629		(4,098	)	—		—		—
GNMA		227,584		1,958		(3,016	)		226,526	10		150,947		(3,016	)	—		—		—
Private issue		306,583		1,595		(6,197	)		301,981	7		88,156		(1,339	)	30		88,517		(4,858	)
	$	2,715,814	$	23,418	$	(22,608	)	$	2,716,624	86	$	1,355,713	$	(17,750	)	30	$	88,517	$	(4,858	)

At December 31, 2003, ASB held 116 mortgage-related securities with unrealized losses amounting to $22.6 million. All 116 securities are investment grade and an evaluation by an independent third-party has

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determined that none of the securities are permanently impaired. The unrealized losses in the portfolio are primarily the result of a rise in interest rates since purchase of the affected securities. In other cases, securities with unrealized losses are in sectors of the market that are currently out of favor with bond investors. Contractual principal and interest payments for all securities with unrealized losses continue to be received and management expects full payment of principal at their maturity or call date. Further, management has the ability to hold the securities until a market price recovery.

	December 31, 2002									December 31, 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:
FNMA	$	1,043,407	$	37,207	$	(34	)	$	1,080,580	$	990,049	$	14,959	$	(3,309	)	$	1,001,699
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
Private issue		876,561		8,373		(7,722	)		877,212		894,849		2,689		(17,961	)		879,577
	$	2,684,011	$	60,500	$	(7,832	)	$	2,736,679	$	2,352,706	$	23,780	$	(21,637	)	$	2,354,849

At December 31, 2003, ASB’s available-for-sale federal agency obligations had contractual due dates in November 2008.

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, 2003 and 2002 was 4.67% and 5.62%, respectively.

In 2003, substantially all of ASB’s security purchases were mortgage-related securities issued by FNMA, FHLMC and GNMA. The securities purchased were primarily hybrid adjustable rate and fixed-rate pass-through securities. In 2003, repayments on private-issue mortgage-related securities exceeded purchases of these securities, resulting in a $575 million decrease in the private-issue mortgage-related securities portfolio held at December 31, 2003 in comparison with that portfolio at December 31, 2002.

In 2003, 2002 and 2001, proceeds from sales of available-for-sale mortgage-related securities were $243 million, $77 million and $701 million resulting in gross realized gains of $4.2 million, $0.4 million and $9.9 million and gross realized losses of $0.1 million, $1.0 million and $2.9 million, respectively.

ASB pledged mortgage-related securities with a carrying value of approximately $71 million and $78 million at December 31, 2003 and 2002, respectively, as collateral to secure public funds and deposits with the Federal Reserve Bank of San Francisco. At December 31, 2003 and 2002, mortgage-related securities sold under agreements to repurchase had a carrying value of $942 million and $784 million, respectively.

As of December 31, 2003, 2002 and 2001, ASB’s held-to-maturity investment securities consisted of stock in FHLB of Seattle. ASB did not sell held-to-maturity investment and mortgage-related securities in 2003, 2002 or 2001.

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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. In the second quarter of 2000, ASB reclassified these trust certificates from held-to-maturity status to available-for-sale status in its financial statements, recognizing a $3.8 million net loss ($5.8 million pretax) on the writedown of these securities to their then-current estimated fair value. In the first six months of 2001, ASB recognized an additional $4.0 million net loss ($6.2 million pretax) on the writedown of three of these trust certificates to their then-current estimated fair value. In April 2001, ASB sold one of the trust certificates for $30 million, an amount approximating the original purchase price. After PaineWebber Incorporated (PaineWebber) (the broker that sold the remaining three trust certificates to ASB) rejected ASB’s demand that the transactions be rescinded, ASB filed a lawsuit against PaineWebber.

To bring ASB into compliance with the OTS’ directive, ASB directed the trustees to terminate the principal swap component of the three trust certificates and received $43 million from the swaps. Prior to terminating the swaps, ASB had received $2 million of cash from the three trust certificates. After terminating the swaps, the related equity notes were sold by the swap counterparty to HEI. 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, 2003, HEI had received $12.2 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, 2003, held cash and collateralized corporate debt securities having an estimated par value of approximately $1.6 billion. The entities manage the portfolio of collateralized debt securities, pay expenses and make payments to the various class note holders as specified in the various note agreements. HEI is not the primary beneficiary of these entities. These purchases by HEI were made pursuant to the terms of an agreement between HEI and ASB, which, among other things, requires ASB to reimburse HEI for any losses related to the income notes, but only from the proceeds of any recovery from PaineWebber.

Due to the uncertainty of future cash flows, HEI is accounting for the income notes under the cost recovery method of accounting. In the second half of 2001, in 2002 and in 2003, HEI recognized net losses of $5.6 million ($8.7 million pretax), $2.9 million ($4.5 million pretax) and nil, respectively, on the writedown of the three income notes to their then-current estimated fair value based upon an independent third party valuation that is updated quarterly. As of December 31, 2003, the estimated fair value and carrying value of the income notes totaled approximately $12.1 million, including valuation adjustments totaling $7.7 million recorded in accumulated other comprehensive income (AOCI). HEI could incur additional losses from the ultimate disposition of these income notes due to further “other-than-temporary” declines in their fair value. HEI’s maximum pre-tax exposure to additional financial statement loss as a result of its ownership of the income notes is $4.4 million as of December 31, 2003 (fair value of $12.1 million less AOCI valuation adjustment of $7.7 million).

ASB’s first amended complaint against PaineWebber alleged that, in connection with the sale of the three trust certificates to ASB, PaineWebber violated the Hawaii Uniform Securities Act and breached fiduciary duties it owed to ASB, among other claims. A counterclaim asserted by PaineWebber against ASB alleged violations of the federal securities laws, misrepresentation and fraud and breach of contract. In light of a court ruling limiting ASB’s ability to recover the damages incurred after HEI purchased the income notes, HEI commenced a separate lawsuit against PaineWebber in September 2003.

HEI and ASB on one side, and PaineWebber on the other, agreed to settle all claims and counterclaims asserted in the two lawsuits shortly before trial of ASB’s case was to begin. The final settlement agreement, the terms of which are confidential, was signed on December 31, 2003. Amounts received by HEI and ASB under the settlement agreement were recognized in the fourth quarter of 2003.

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Loans receivable

December 31	2003			2002
(in thousands)
Real estate loans
One-to-four unit residential and commercial	$	2,623,478		$	2,526,505
Construction and development		72,823			46,150
		2,696,301			2,572,655
Loans secured by savings deposits		7,572			8,034
Consumer loans		215,171			237,819
Commercial loans		286,068			247,114
		3,205,112			3,065,622
Undisbursed portion of loans in process		(27,052	)		(21,413	)
Deferred fees and discounts, including net purchase accounting discounts		(20,765	)		(19,180	)
Allowance for loan losses		(44,285	)		(45,435	)
Loans held to maturity		3,113,010			2,979,594
Residential loans held for sale		8,969			14,395
	$	3,121,979		$	2,993,989

At December 31, 2003 and 2002, the weighted-average interest rate for loans receivable was 5.73% and 6.52%, respectively.

At December 31, 2003 and 2002, ASB had pledged loans with an amortized cost of approximately $1.2 billion and $1.4 billion, respectively, as collateral to secure advances from the FHLB of Seattle.

At December 31, 2003 and 2002, 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 $95 million and $61 million, respectively. The $34 million increase in such loans in 2003 were primarily attributed to new loans made to related interests of directors of ASB. At December 31, 2003 and 2002, $83 million and $50 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, 2003, ASB had impaired loans totaling $19.3 million, which consisted of $7.0 million of income property loans and $12.3 million of commercial loans. 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. The average balances of impaired loans during 2003, 2002 and 2001 were $22.5 million, $26.0 million and $23.2 million, respectively. At December 31, 2003, 2002 and 2001, ASB had impaired loans totaling $7.3 million, $2.3 million and $6.4 million, respectively, for which there were related allowances for loan losses of $1.0 million, $0.3 million and $3.7 million, respectively.

At December 31, 2003 and 2002, ASB had nonaccrual and renegotiated loans of $13 million and $26 million, respectively.

ASB realized $0.1 million, $0.4 million and $1.5 million of interest income on nonaccrual loans in 2003, 2002 and 2001, respectively. If these loans would have earned interest in accordance with their original contractual terms ASB would have realized $0.5 million, $0.9 million and $2.2 million in 2003, 2002 and 2001, respectively.

ASB services real estate loans owned by third parties ($0.6 billion, $0.9 billion and $1.1 billion at December 31, 2003, 2002 and 2001, 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, 2003 and 2002, commitments not reflected in the consolidated balance sheets consisted of commitments to originate loans, other than loans in process, of $93.4 million and $69.4 million, respectively. Of such commitments at December 31, 2003, $51.5 million was for variable-rate loans and $41.9 million was for fixed-

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rate loans. Since certain of the commitments are expected to expire without being drawn upon, the total commitment amounts do not necessarily represent future cash requirements. At December 31, 2003 and 2002, other commitments not reflected in the consolidated balance sheets consisted of standby, commercial and banker’s acceptance letters of credit of $12.7 million and $11.2 million, respectively, and unused lines of credit of $704.5 million and $690.3 million, respectively.

At December 31, 2003 and 2002, ASB had commitments to sell loans of $16 million and $14 million, respectively. The loans are included in loans receivable held for sale or represent commitments to make loans at an interest rate set prior to funding (rate lock commitments). Rate lock commitments guarantee a specified interest rate for a loan if ASB’s underwriting standards are met, but do not obligate the potential borrower. Rate lock commitments on loans intended to be sold in the secondary market are derivative instruments, but have not been “designated” hedges. Rate lock commitments are carried at fair value and adjustments are recorded in “Other income,” with an offset on the balance sheet in “Other” liabilities. At December 31, 2003 and 2002, rate lock commitments were made on loans totaling $8.0 million and nil, respectively. To offset the impact of changes in market interest rates on the rate lock commitments on loans held for sale, ASB utilizes short-term forward sale contracts. Forward sale contracts are also derivative instruments, but have not been “designated” hedges, and thus the associated changes in fair value are also recorded in “Other income,” with an offset on the balance sheet in “Other” assets or liabilities. As of December 31, 2003 and 2002, the notional amounts for forward sales contracts were $16 million and $14 million, respectively. Valuation models are applied using current market information to estimate market value. For 2003 and 2002, the net loss on derivatives was less than $40,000.

Allowance for loan losses. Changes in the allowance for loan losses were as follows:

Years ended December 31,	2003			2002			2001
(dollars in thousands)
Allowance for loan losses, January 1	$	45,435		$	42,224		$	37,449
Provision for loan losses		3,075			9,750			12,500
Charge-offs, net of recoveries
Real estate loans		(604	)		1,876			3,414
Other loans		4,829			4,663			4,311
Net charge-offs		4,225			6,539			7,725
Allowance for loan losses, December 31	$	44,285		$	45,435		$	42,224
Ratio of allowance for loan losses, December 31, to average loans outstanding		1.44	%		1.60	%		1.42	%
Ratio of provision for loan losses during the year to average loans outstanding		0.10	%		0.34	%		0.42	%
Ratio of net charge-offs during the year to average loans outstanding		0.14	%		0.23	%		0.26	%

Real estate acquired in settlement of loans. At December 31, 2003 and 2002, ASB’s real estate acquired in settlement of loans was $7.9 million and $12.1 million, respectively.

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Deposit liabilities

December 31	2003				2002
(in thousands)	Weighted- average stated rate		Amount		Weighted- average stated rate		Amount
Savings	0.46	%	$	1,497,146	0.75	%	$	1,226,337
Other checking	0.04			700,559	0.13			620,631
Money market	0.40			342,845	1.04			442,735
Commercial checking	—			285,213	—			241,996
Term certificates	3.52			1,200,487	3.80			1,269,073
	1.26	%	$	4,026,250	1.65	%	$	3,800,772

At December 31, 2003 and 2002, deposit accounts of $100,000 or more totaled $1.0 billion and $0.8 billion, respectively.

The approximate amounts of term certificates outstanding at December 31, 2003 with scheduled maturities for 2004 through 2008 were $622.2 million in 2004, $358.5 million in 2005, $85.0 million in 2006, $54.9 million in 2007 and $38.8 million in 2008.

Interest expense on savings deposits by type of deposit was as follows:

Years ended December 31	2003		2002		2001
(in thousands)
Term certificates	$	43,413	$	51,968	$	84,945
Savings		7,524		14,512		20,004
Money market		2,424		6,092		7,432
Interest-bearing checking		447		1,059		4,150
	$	53,808	$	73,631	$	116,531

Securities sold under agreements to repurchase

December 31, 2003
Maturity	Repurchase liability		Weighted-average interest rate		Collateralized by mortgage- related securities– fair value plus accrued interest
(in thousands)
Overnight	$	47,930	0.90	%	$	57,694
1 to 29 days		61,937	0.97			78,602
30 to 90 days		105,918	1.55			134,417
Over 90 days		615,550	2.95			674,659
	$	831,335	2.50	%	$	945,372

At December 31, 2003, 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, 2003 and 2002, ASB had agreements to repurchase identical securities totaling $831 million and $667 million, respectively. At December 31, 2003 and 2002, the weighted-average rate on securities sold under agreements to repurchase was 2.50% and 3.17%, respectively, and the weighted-average remaining days to

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maturity was 640 days and 454 days, respectively. During 2003, 2002 and 2001, securities sold under agreements to repurchase averaged $807 million, $663 million and $629 million, respectively, and the maximum amount outstanding at any month-end was $958 million, $751 million and $722 million, respectively.

Advances from Federal Home Loan Bank

December 31	2003				2002
(in thousands)	Weighted- average stated rate		Amount		Weighted- average stated rate		Amount
Due in
2003	NA			NA	4.58	%	$	272,700
2004	3.39	%	$	123,822	4.95			329,321
2005	4.40			282,731	5.98			382,231
2006	3.63			168,500	6.70			36,000
2007	3.90			166,000	3.81			156,000
2008	5.45			168,000	—			—
Thereafter	4.80			108,000	—			—
	4.28	%	$	1,017,053	5.10	%	$	1,176,252

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.

ASB restructured a total of $389 million of FHLB advances during 2003. The restructurings involved paying off existing, higher rate FHLB advances with advances that have lower rates and longer maturities. The restructurings were executed in two transactions, with $258 million of advances restructured in April 2003 and $131 million of advances restructured in June 2003. In the April 2003 restructuring, the FHLB advances that were paid off had an average rate of 7.17% and an average remaining maturity of 2.02 years. The new advances had an average rate of 5.57% and an average maturity of 4.80 years at the time of the restructuring. The April 2003 restructuring resulted in a reduction of interest expense on these FHLB advances of approximately $3.1 million for 2003. In the June 2003 restructuring, the FHLB advances that were paid off had an average rate of 5.21% and an average remaining maturity of 0.93 years. The new advances had an average rate of 3.21% and an average maturity of 4.12 years at the time of the restructuring. The June 2003 restructuring resulted in a reduction of interest expense on these FHLB advances of approximately $1.5 million for 2003.

Common stock equity. As of December 31, 2003, 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, 2003, HEI’s maximum obligation to contribute additional capital had been reduced to approximately $28 million.

The change in accumulated other comprehensive income (loss) from December 31, 2002 to December 31, 2003 was primarily due to the change in the market value of the available-for-sale mortgage-related securities. Changes in the market value of mortgage-related securities do not result in a charge to net income in the absence of an “other-than-temporary” impairment in the value of the securities.

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5 • Short-term borrowings

No commercial paper was outstanding at December 31, 2003 and 2002.

At December 31, 2003 and 2002, HEI maintained bank lines of credit which totaled $90 million ($30 million maturing in each of April and June 2004, $10 million in October 2004 and $20 million in December 2004) and $70 million, respectively, and HECO maintained bank lines of credit which totaled $90 million ($50 million maturing in April 2004, $10 million in May 2004 and $30 million in June 2004) and $100 million, respectively. HEI maintains lines of credit (at a base rate (Prime, Fed Funds, Bank Base, Eurodollar or LIBOR rate) plus a margin ranging from 0 to 125 basis points) and HECO maintains lines of credit (at a base rate (Prime, Fed Funds, Bank Base, Bank Quoted, Eurodollar or LIBOR rate) plus a margin ranging from 0 to 80 basis points) 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 during 2003 and 2002.

6 • Long-term debt

December 31	2003			2002
(in thousands)
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
4.75-7.60%, due 2020-2023		232,000			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			40,000
		717,900			725,900
Less funds on deposit with trustees		(14,013	)		(16,111	)
Less unamortized discount		(4,467	)		(4,519	)
		699,420			705,270
Promissory notes
Variable rate, paid in 2003		—			100,000
4.00-7.56%, due in various years through 2014		365,000			301,000
		365,000			401,000
	$	1,064,420		$	1,106,270

At December 31, 2003, the aggregate principal payments required on long-term debt for 2004 through 2008 are $1 million in 2004, $37 million in 2005, $110 million in 2006, $10 million in 2007 and $50 million in 2008.

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7 • HEI- and HECO-obligated preferred securities of trust subsidiaries

December 31	2003		2002		Liquidation value per security
(in thousands, except per security amounts and number of securities)
Hawaiian Electric Industries Capital Trust I* 8.36% Trust Originated Preferred Securities (4,000,000 securities)**	$	100,000	$	100,000	$	25
HECO Capital Trust I* 8.05% Cumulative Quarterly Income Preferred Securities, Series 1997 (2,000,000 securities)***		50,000		50,000		25
HECO Capital Trust II* 7.30% Cumulative Quarterly Income Preferred Securities, Series 1998 (2,000,000 securities)****		50,000		50,000		25
	$	200,000	$	200,000

* Delaware grantor trust.

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

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

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

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

The Partnership is a Delaware limited partnership managed by Hycap, its sole general partner, and exists for the exclusive purposes of (a) purchasing certain eligible debt instruments of HEI and its subsidiaries (collectively, the Investment Instruments) in the amount of $120 million and certain U.S. government obligations and commercial paper of unaffiliated entities (Eligible Debt Securities) with the proceeds from (i) the 1997 sale of its 8.36% Partnership Preferred Securities to the Trust, its sole limited partner, and (ii) a capital contribution in exchange for the general partner interest, (b) receiving interest and other payments on the Investment Instruments and Eligible Debt Securities, (c) making distributions on the 8.36% Partnership Preferred Securities and general partner interest if, as, and when declared by the general partner, (d) making authorized additional investments in Investment Instruments and Eligible Debt Securities and disposing of any such investments, and (e) other activities necessary for carrying out the purposes of the Partnership. HEI guarantees payment by the Partnership of distributions on the Partnership Preferred Securities insofar as such distributions have been declared by the Partnership and the Partnership has sufficient funds for the payment of such distributions.

HECO Capital Trust I (Trust I) exists for the exclusive purposes of (i) issuing in 1997 trust securities, consisting of 8.05% Cumulative Quarterly Income Preferred Securities, Series 1997 (1997 Trust Preferred Securities) ($50 million) and trust common securities ($1.5 million to HECO), (ii) investing the proceeds of the trust securities in 8.05% Junior Subordinated Deferrable Interest Debentures, Series 1997 (1997 Debentures) issued by HECO in the principal amount of $31.5 million and issued by each of MECO and HELCO in the respective principal amounts of $10 million, (iii) making distributions on the 1997 Trust Preferred Securities and trust common securities and (iv) engaging in only those other activities necessary or incidental thereto. The 1997 Debentures, together with the

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obligations of HECO, MECO and HELCO under an expense agreement and HECO’s obligations under its trust guarantee and its guarantee of the obligations of MECO and HELCO under their respective debentures, are the sole assets of Trust I.

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

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 and include 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. The Directors’ Plan has been frozen since 1996, and no participants have accrued any benefits after that time. The plan will be terminated at the time all remaining benefits have been paid.

Each participating employer reserves the right to terminate its participation in the applicable plans at any time, and HEI and ASB reserve the right to terminate their respective plans 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 in the Plans are covered up to certain limits under insurance provided by the Pension Benefit Guaranty Corporation.

The Participating Employers contribute amounts to a master pension trust for the Plans in accordance with the funding requirements of ERISA and considering the deductibility of contributions under the Internal Revenue 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 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. Health benefits are also provided to dependents of eligible employees. The contribution for health benefits paid by the participating employers is based on retirees’ years of service and retirement dates. Generally, employees are eligible for these benefits if, upon retirement from

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active employment, they are eligible to receive benefits from the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries.

Among other provisions, the plan provides prescription drug benefits for Medicare-eligible participants who retire after 1998. Retirees who are eligible for the drug benefits are required to pay a portion of the cost each month.

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was signed into law. The Act introduces a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare benefit. The Act may have the impact of reducing plan liabilities and future net periodic postretirement benefit cost. For example, some participants may elect to opt out of the plan and participate instead in the Medicare drug plan. In such case, the plan would have no further liabilities to provide benefits for such participants. Plan amendments taking the Medicare drug benefits into account could also reduce plan liabilities and net periodic cost. In accordance with FASB’s Staff Position No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” the Company has elected to defer recognition of the effects of the Act in any measures of the benefit obligation or cost. Specific authoritative guidance on the accounting for the federal subsidy is pending and that guidance, when issued, could require the Company to change previously reported information.

The postretirement benefits other than pensions 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 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 Company’s balance sheet were as follows:

	Pension benefits						Other benefits
(in thousands)	2003			2002			2003			2002
Benefit obligation, January 1	$	728,780		$	646,197		$	159,430		$	146,486
Service cost		22,918			20,215			3,580			3,135
Interest cost		47,970			45,806			10,408			10,158
Amendments		19			(34	)		—			—
Actuarial loss		66,483			52,597			13,936			6,051
Benefits paid		(37,870	)		(36,001	)		(7,246	)		(6,400	)
Benefit obligation, December 31		828,300			728,780			180,108			159,430
Fair value of plan assets, January 1		589,092			719,112			75,926			90,041
Actual return (loss) on plan assets		134,829			(97,541	)		19,212			(14,169	)
Employer contribution		37,803			3,522			10,297			6,454
Benefits paid		(37,870	)		(36,001	)		(7,246	)		(6,400	)
Fair value of plan assets, December 31		723,854			589,092			98,189			75,926
Funded status		(104,446	)		(139,688	)		(81,919	)		(83,504	)
Unrecognized net actuarial loss		197,238			209,828			26,724			24,361
Unrecognized net transition obligation		27			981			29,503			32,781
Unrecognized prior service cost (gain)		(6,365	)		(6,999	)		183			196
Net amount recognized, December 31	$	86,454		$	64,122		$	(25,509	)	$	(26,166	)
Amounts recognized in the balance sheet consist of:
Prepaid benefit cost	$	95,020		$	70,328		$	—		$	—
Accrued benefit liability		(11,005	)		(15,063	)		(25,509	)		(26,166	)
Intangible asset		67			690			—			—
Accumulated other comprehensive income		2,372			8,167			—			—
Net amount recognized, December 31	$	86,454		$	64,122		$	(25,509	)	$	(26,166	)

The defined benefit pension plans’ accumulated benefit obligations as of December 31, 2003 and 2002 were $691 million and $603 million, respectively. Depending on the performance of the pension plan assets, the status of interest rates and numerous other factors, the Company could be required to recognize an additional minimum liability as prescribed by SFAS No. 87, “Employers’ Accounting for Pensions,” in the future. If recognizing a liability is required, the liability would largely be recorded as a reduction to stockholders’ equity through a non-cash charge to accumulated other comprehensive income, and would result in the removal of the prepaid pension asset ($95 million as of December 31, 2003) from the Company’s balance sheet.

The measurement dates used to determine pension and other postretirement benefit measurements for the defined benefit plans were December 31, 2003, 2002 and 2001.

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The weighted-average asset allocation of pension and other postretirement benefit defined benefit plans was as follows:

	Pension benefits								Other benefits
					Investment policy								Investment policy
December 31	2003		2002		Target		Range		2003		2002		Target		Range
Asset category
Equity securities	76	%	69	%	74	%	67-80	%	77	%	71	%	75	%	70-80	%
Debt securities	22		29		25		20-30	%	22		28		25		20-30	%
Other	2		2		1		0-3	%	1		1		—		—
	100	%	100	%	100	%			100	%	100	%	100	%

A primary goal of the plans is to achieve long-term asset growth sufficient to pay future benefit obligations at a reasonable level of risk. The investment policy target for pension and other postretirement benefit defined benefit plans reflects the philosophy that long-term growth can best be achieved by prudent investments in equity securities while balancing overall fund volatility by an appropriate allocation to fixed income securities. In order to reduce the level of portfolio risk and volatility in returns, efforts have been made to diversify the plans investments by: asset class, geographic region, market capitalization and investment style.

The expected long-term rate of return assumption was based on an asset/liability study performed by the plans’ actuarial and investment consultants, which projected the return over the long term to be in excess of 9%, based on the target asset allocation.

The Company’s current estimate of contributions to the retirement benefit plans in 2004 is $14 million.

The following weighted-average assumptions were used in the accounting for the plans:

	Pension benefits						Other benefits
December 31	2003		2002		2001		2003		2002		2001
Benefit obligation
Discount rate	6.25	%	6.75	%	7.25	%	6.25	%	6.75	%	7.25	%
Expected return on plan assets	9.0		9.0		10.0		9.0		9.0		10.0
Rate of compensation increase	4.6		4.6		4.6		4.6		4.6		4.6
Net periodic benefit cost (years ended)
Discount rate	6.75		7.25		7.5		6.75		7.25		7.5
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, 2003, the assumed health care trend rates for 2004 and future years were as follows: medical, 10.00%, grading down to 4.25%; dental, 4.25%; and vision, 3.25%. 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%.

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The components of net periodic benefit cost (return) were as follows:

	Pension benefits									Other benefits
Years ended December 31	2003			2002			2001			2003			2002			2001
(in thousands)
Service cost	$	22,918		$	20,215		$	19,390		$	3,580		$	3,135		$	3,051
Interest cost		47,970			45,806			43,512			10,408			10,158			9,348
Expected return on plan assets		(59,790	)		(80,958	)		(80,281	)		(7,639	)		(10,023	)		(10,032	)
Amortization of unrecognized transition obligation		954			2,270			2,326			3,278			3,278			3,278
Amortization of prior service cost (gain)		(614	)		(505	)		(482	)		13			13			13
Recognized actuarial loss (gain)		4,035			(3,489	)		(8,183	)		—			(716	)		(2,599	)
Net periodic benefit cost (return)	$	15,473		$	(16,661	)	$	(23,718	)	$	9,640		$	5,845		$	3,059

Of the net periodic pension benefit costs/returns, the Company recorded expense of $13 million in 2003, and income of $11 million in 2002 and $17 million in 2001, and charged or credited the remaining amounts primarily to electric utility plant. Of the net periodic other than pension benefit costs, the Company expensed $7 million, $4 million and $2 million in 2003, 2002 and 2001, 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 $13 million, $11 million and nil, respectively, as of December 31, 2003 and $55 million, $42 million and $29 million, respectively, as of December 31, 2002.

The health care cost trend rate assumptions can have a significant effect on the amounts reported for other benefits. At December 31, 2003, 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 $3.5 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 $4.3 million.

9 • Income taxes

The components of income taxes attributable to income from continuing operations were as follows:

Years ended December 31	2003			2002			2001
(in thousands)
Federal
Current	$	58,763		$	24,791		$	56,648
Deferred		3,032			35,614			(730	)
Deferred tax credits, net		(1,504	)		(1,557	)		(1,567	)
		60,291			58,848			54,351
State
Current		2,213			2,668			248
Deferred		1,307			1,139			1,112
Deferred tax credits, net		556			1,037			2,446
		4,076			4,844			3,806
	$	64,367		$	63,692		$	58,157

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 tax benefits, recognized on the financial statements of HEI Diversified, Inc. (HEIDI) and ASB by $20 million for 2003 and prior years. ASB has taken a dividends received deduction on dividends paid to it by ASB Realty Corporation in state bank franchise tax returns filed in 1999 through 2003. The State of Hawaii Department of Taxation has challenged

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ASB’s position and has issued notices of tax assessment for 1999, 2000 and 2001. In October 2002, ASB filed an appeal with the State Board of Review, First Taxation District (Board). In May 2003, the Board heard ASB’s case and issued its decision in favor of the Department of Taxation. As required under Hawaii law, ASB paid the taxes and interest assessed ($17 million) in June 2003 and filed a notice of appeal with the Hawaii Tax Appeals Court. Trial is schedule to begin in July 2004. ASB believes that its tax position is proper, and the payment of the assessed bank franchise taxes and interest is accordingly being treated like a deposit rather than an expense for financial statement purposes and thus has not affected earnings to date. If it becomes probable that ASB will not prevail on its tax appeal, ASB may be required to write off the deposit and expense the related bank franchise taxes and interest for subsequent years, resulting in a total charge to income (net of federal income tax benefits) of approximately $23 million through December 31, 2003.

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	2003			2002			2001
(in thousands)
Amount at the federal statutory income tax rate	$	63,845		$	63,668		$	58,066
Increase (decrease) resulting from:
State income taxes, net of effect on federal income taxes		2,649			3,149			2,474
Preferred stock dividends of subsidiaries		698			698			698
Other, net		(2,825	)		(3,823	)		(3,081	)
	$	64,367		$	63,692		$	58,157

The tax effects of book and tax basis differences that give rise to deferred tax assets and liabilities were as follows:

December 31	2003		2002
(in thousands)
Deferred tax assets
Cost of removal in excess of salvage value	$	69,425	$	63,275
Contributions in aid of construction and customer advances		42,179		46,052
Allowance for loan losses		14,711		15,783
Other		30,804		29,963
		157,119		155,073
Deferred tax liabilities
Property, plant and equipment		237,778		225,305
Leveraged leases		32,911		35,796
Real estate investment trust dividends (federal income taxes only)		19,396		28,409
Net unrealized gains on available-for-sale mortgage-related securities		1,573		16,888
Regulatory assets, excluding amounts attributable to property, plant and equipment		25,514		24,794
FHLB stock dividend		18,645		16,547
Other		47,892		42,765
		383,709		390,504
Net deferred income tax liability	$	226,590	$	235,431

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 most of the benefits of the deferred tax assets and has provided an immaterial valuation allowance for deferred tax benefits recorded during 2003 and no valuation allowance for deferred tax benefits recorded in 2002 and prior years.

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10 • Cash flows

Supplemental disclosures of cash flow information. In 2003, 2002 and 2001, the Company paid interest amounting to $196 million, $222 million and $293 million, respectively.

In 2003, 2002 and 2001, the Company paid income taxes amounting to $53 million, $60 million and $30 million, respectively.

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

ASB received $0.4 billion in mortgage-related securities in exchange for loans in 2001.

In 2003, ASB restructured a total of $389 million of FHLB advances with lower rate, longer maturity advances.

In each of 2003, 2002 and 2001, 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.

The estimated fair value of noncash contributions in aid of construction amounted to $14 million, $4 million and $2 million in 2003, 2002 and 2001, 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, 2003, HECO and its subsidiaries could not transfer approximately $449 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 statute, regulation, or agreement between ASB and the OTS. At December 31, 2003, ASB could transfer approximately $130 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, 2003, 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, 2003, various securities rating agencies rated the private-issue mortgage-related securities held by ASB as investment grade.

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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. In November 2001, HEIPC sold HPG for a nominal gain and 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). No amounts have been accrued related to the indemnities and the maximum potential exposure is limited to 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 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 1998 and 1999, the HEIPC Group invested $9.7 million to acquire shares in Cagayan Electric Power & Light Co., Inc. (CEPALCO), an electric distribution company in the Philippines. This investment is classified as available for sale. The HEIPC Group recognized impairment losses of approximately $3 million in 2001 and $5 million in 2003 to adjust this investment to its estimated net realizable value at the time. In January 2004, the HEIPC Group signed

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an agreement for the sale of HEIPC Philippine Development, LLC, the HEIPC Group company that holds its interest in CEPALCO. The sale will be recorded in the first quarter of 2004.

Summary financial information for the discontinued operations of the HEIPC Group is as follows:

Years ended December 31	2003			2002		2001
(in thousands)
Operations
Revenues (including equity losses)	$	—		$	—	$	4,233
Operating loss		—			—		(233	)
Interest expense		—			—		(1,050	)
Income tax benefits		—			—		29
Loss from operations		—			—		(1,254	)
Disposal
Loss, including a provision of $1 million and $8 million for losses from operations during phase-out period in 2003 and 2001, respectively		(6,017	)		—		(34,784	)
Income tax benefits		2,147			—		12,463
Loss on disposal		(3,870	)		—		(22,321	)
Loss from discontinued operations of HEIPC	$	(3,870	)	$	—	$	(23,575	)

As of December 31, 2003, the remaining net assets of the discontinued international power operations, after the write-offs and writedowns described above, amounted to $11 million (included in “Other” assets) and consisted primarily of the $2 million investment in CEPALCO and deferred taxes receivable, reduced by a reserve for losses from operations during the phase-out period (primarily for legal fees). In 2003, HEIPC increased its reserve for future expenses by $1 million. The amounts that HEIPC will ultimately realize from the disposition or sale of the international power assets could differ materially from the recorded amounts and gains or additional losses may be sustained in the future. This could occur, for example, if the HEIPC Group is successful in recovery of all or part of the costs incurred in connection with the China joint venture interest. Alternatively, further losses may be sustained if the expenditures made in seeking recovery of the costs incurred in connection with the China joint venture interest exceed the total of any recovery ultimately achieved and the amount provided for in HEI’s reserve for discontinued operations.

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, 2003 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, 2003, the remaining net assets of the discontinued residential real estate development operations amounted to $1 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 from the recorded amounts.

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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 federal funds sold. 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 terms of the agreements and the present creditworthiness of the counterparties, current settlement values or quoted market prices of comparable instruments.

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The estimated fair values of certain of the Company’s financial instruments were as follows:

December 31	2003				2002
(in thousands)	Carrying or notional amount		Estimated fair value		Carrying or notional amount		Estimated fair value
Financial assets
Cash and equivalents	$	223,310	$	223,310	$	244,525	$	244,525
Federal funds sold		56,678		56,678		—		—
Available-for-sale investment and mortgage-related securities		2,728,748		2,728,748		2,744,650		2,744,650
Held-to-maturity investment securities		94,624		94,624		89,545		89,545
Loans receivable, net		3,121,979		3,179,392		2,993,989		3,108,659
Financial liabilities
Deposit liabilities		4,026,250		4,057,267		3,800,772		3,838,317
Securities sold under agreements to repurchase		831,335		842,272		667,247		685,022
Advances from Federal Home Loan Bank		1,017,053		1,066,697		1,176,252		1,248,001
Long-term debt		1,064,420		1,113,163		1,106,270		1,146,368
HEI- and HECO-obligated preferred securities of trust subsidiaries		200,000		205,120		200,000		200,720
Off-balance sheet items
Loans serviced for others		568,807		4,378		887,158		6,776
Unused lines and letters of credit		717,205		23,702		701,467		44,539

At December 31, 2003 and 2002, 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									Years ended December 31
(in thousands, except per share amounts)	March 31		June 30			Sept. 30		Dec.31
2003
Revenues	$	424,636	$	448,756		$	453,703	$	454,221	$	1,781,316
Operating income 1		59,088		61,453			68,235		74,791		263,567
Net income 1
Continuing operations		24,327		25,760			30,522		37,439		118,048
Discontinued operations		—		(3,870	)		—		—		(3,870	)
		24,327		21,890			30,522		37,439		114,178
Basic earnings (loss) per common share 3
Continuing operations		0.66		0.69			0.81		0.99		3.16
Discontinued operations		—		(0.10	)		—		—		(0.10	)
		0.66		0.59			0.81		0.99		3.06
Diluted earnings (loss) per common share 4
Continuing operations		0.66		0.69			0.81		0.99		3.15
Discontinued operations		—		(0.10	)		—		—		(0.10	)
		0.66		0.59			0.81		0.99		3.05
Dividends per common share		0.62		0.62			0.62		0.62		2.48
Market price per common share 5
High		46.11		46.59			45.95		48.00		48.00
Low		38.20		39.53			41.25		43.32		38.20
2002
Revenues	$	377,436	$	409,002		$	431,560	$	435,703	$	1,653,701
Operating income 2		64,604		70,626			71,738		59,465		266,433
Net income 2		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

(1) For 2003, amounts for the fourth quarter reflect amounts recognized from the settlement of lawsuits ($9.5 million pretax; $5.8 million after-tax) and amounts for the second quarter reflect an additional writedown of the HEIPC Group’s investment in CEPALCO and an increase in its reserve for future expenses expected to be incurred in seeking recovery of the costs of the HEIPC Group’s China project ($6.0 million pre-tax; $3.9 million after-tax).

(2) For 2002, amounts reflect stock option compensation expense under the fair value based method of accounting prescribed by SFAS No. 123, as amended. See Note 1.

(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.

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HEI Directors

Robert F. Clarke, 61 (1)* Chairman, President and Chief Executive Officer Hawaiian Electric Industries, Inc. 1989	T. Michael May, 57* President and Chief Executive Officer Hawaiian Electric Company, Inc. 1995	Oswald K. Stender, 72 (3, 4) Real Estate Consultant 1993
Don E. Carroll, 62 (2, 3, 4) Chairman Oceanic Cablevision (cable television broadcasting) 1996	Bill D. Mills, 52 (1, 3, 4) Chairman Mills Investment Company (real estate development) 1988	Kelvin H. Taketa, 49 (2, 3, 4) President and Chief Executive Officer Hawaii Community Foundation (statewide charitable foundation) 1993
Shirley J. Daniel, Ph.D., 50 (2)* Professor of Accountancy University of Hawaii-Manoa College of Business Administration (higher education) 2002	A. Maurice Myers, 63 (3, 4) Chairman, President and Chief Executive Officer Waste Management, Inc. (environmental services) 1991	Jeffrey N. Watanabe, 61 (4)* Managing Partner Watanabe Ing Kawashima & Komeiji LLP (private law firm) 1987
Constance H. Lau, 51* President and Chief Executive Officer American Savings Bank, F.S.B. 2001	Diane J. Plotts, 68 (1, 2, 3)* Business Advisor 1987	Committees of the Board of Directors (1) Executive:       Bill D. Mills, Chairman (2) Audit:       Diane J. Plotts, Chairman (3) Compensation:       Bill D. Mills, Chairman (4) Nominating & Corporate Governance:       Kelvin H. Taketa, Chairman
Victor Hao Li, S.J.D., 62 (2) Co-chairman Asia Pacific Consulting Group (international business consultant) 1988	James K. Scott, Ed.D., 52 (2, 4)* President Punahou School (private education) 1995

Year denotes year of first election to the board of directors.

* Also member of one or more subsidiary boards.

Information as of February 11, 2004.

HEI Executive Officers

Robert F. Clarke, 61 Chairman, President and Chief Executive Officer 1987	Charles F. Wall, 64 Vice President and Corporate Information Officer 1990	T. Michael May, 57 * President and Chief Executive Officer Hawaiian Electric Company, Inc. 1992
Eric K. Yeaman, 36 Financial Vice President, Treasurer and Chief Financial Officer 2003	Andrew I. T. Chang, 64 Vice President–Government Relations 1985	Constance H. Lau, 51 * President and Chief Executive Officer American Savings Bank, F.S.B. 1984
Peter C. Lewis, 69 Vice President–Administration and Corporate Secretary; Corporate Governance Officer 1968	Curtis Y. Harada, 48 Controller 1989

Year denotes year of first employment by the Company.

* Mr. May and Ms. Lau are deemed to be executive officers of HEI under Rule 3b-7 of the Securities Exchange Act of 1934 general rules and regulations.

Information as of February 11, 2004.

89

Shareholder Information

CORPORATE HEADQUARTERS Hawaiian Electric Industries, Inc. 900 Richards Street Honolulu, Hawaii 96813 Telephone: 808-543-5662 Facsimile: 808-543-7966 Mailing address: P. O. Box 730 Honolulu, Hawaii 96808-0730 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 15, 2004, a copy of the 2003 Form 10-K annual report 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 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 shareholder questions, or to request 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 shareholders of record on or about the 10th 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 shareholders of record on the 5th 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 20, 2004, 9:30 a.m. American Savings Bank Tower 1001 Bishop Street 8th 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 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.

90

EX-32.1

HEI Exhibit 32.1

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 Current Report of Hawaiian Electric Industries, Inc. (HEI) on Form 8-K as filed with the Securities and Exchange Commission on the date hereof (the Report), I, Robert F. Clarke, Chief Executive Officer of HEI, certify, pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

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

(2) The consolidated information contained in the Report fairly presents, in all material respects, the financial condition as of December 31, 2003 and results of operations for the year ended December 31, 2003 of HEI and its subsidiaries.

/s/ Robert F. Clarke

Robert F. Clarke

Chairman, President and Chief Executive Officer of HEI

Date: February 26, 2004

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

EX-32.2

HEI Exhibit 32.2

Hawaiian Electric Industries, Inc.

Written Statement of Chief Financial Officer Pursuant to

18 U.S.C. Section 1350,

as Adopted by

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Current Report of Hawaiian Electric Industries, Inc. (HEI) on Form 8-K as filed with the Securities and Exchange Commission on the date hereof (the Report), I, Eric K. Yeaman, Chief Financial Officer of HEI, certify, pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

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

(2) The consolidated information contained in the Report fairly presents, in all material respects, the financial condition as of December 31, 2003 and results of operations for the year ended December 31, 2003 of HEI and its subsidiaries.

/s/ Eric K. Yeaman

Eric K. Yeaman

Financial Vice President, Treasurer and
Chief Financial Officer of HEI

Date: February 26, 2004

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

EX-32.3

HECO Exhibit 32.3

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 Current Report of Hawaiian Electric Company, Inc. (HECO) on Form 8-K as filed with the Securities and Exchange Commission on the date hereof (the HECO Report), I, T. Michael May, Chief Executive Officer of HECO, certify, pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

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

(2) The HECO consolidated information contained in the HECO Report fairly presents, in all material respects, the financial condition as of December 31, 2003 and results of operations for the year ended December 31, 2003 of HECO and its subsidiaries.

/s/ T. Michael May

T. Michael May

President and Chief Executive Officer of HECO

Date: February 26, 2004

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

EX-32.4

HECO Exhibit 32.4

Hawaiian Electric Company, Inc.

Written Statement of Chief Financial Officer Pursuant to

18 U.S.C. Section 1350,

as Adopted by

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Current Report of Hawaiian Electric Company, Inc. (HECO) on Form 8-K as filed with the Securities and Exchange Commission on the date hereof (the HECO Report), I, Richard A. von Gnechten, Chief Financial Officer of HECO, certify, pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

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

(2) The HECO consolidated information contained in the HECO Report fairly presents, in all material respects, the financial condition as of December 31, 2003 and results of operations for the year ended December 31, 2003 of HECO and its subsidiaries.

/s/ Richard A. von Gnechten

Richard A. von Gnechten

Financial Vice President of HECO

Date: February 26, 2004

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

EX-99

HECO Exhibit 99

Consolidated Statements of Income

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31	2003			2002			2001
(in thousands)
Operating revenues	$	1,393,038		$	1,252,929		$	1,284,312
Operating expenses
Fuel oil		388,560			310,595			346,728
Purchased power		368,076			326,455			337,844
Other operation		155,531			131,910			125,565
Maintenance		64,621			66,541			61,801
Depreciation		110,560			105,424			100,714
Taxes, other than income taxes		130,677			120,118			120,894
Income taxes		50,175			56,729			55,434
		1,268,200			1,117,772			1,148,980
Operating income		124,838			135,157			135,332
Other income
Allowance for equity funds used during construction		4,267			3,954			4,239
Other, net		1,903			3,141			3,197
		6,170			7,095			7,436
Income before interest and other charges		131,008			142,252			142,768
Interest and other charges
Interest on long-term debt		40,698			40,720			40,296
Amortization of net bond premium and expense		2,131			2,014			2,063
Preferred securities distributions of trust subsidiaries		7,675			7,675			7,675
Other interest charges		1,512			1,498			4,697
Allowance for borrowed funds used during construction		(1,914	)		(1,855	)		(2,258	)
Preferred stock dividends of subsidiaries		915			915			915
		51,017			50,967			53,388
Income before preferred stock dividends of HECO		79,991			91,285			89,380
Preferred stock dividends of HECO		1,080			1,080			1,080
Net income for common stock	$	78,911		$	90,205		$	88,300

Consolidated Statements of Retained Earnings

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31	2003			2002			2001
(in thousands)
Retained earnings, January 1	$	542,023		$	495,961		$	443,970
Net income for common stock		78,911			90,205			88,300
Common stock dividends		(57,719	)		(44,143	)		(36,309	)
Retained earnings, December 31	$	563,215		$	542,023		$	495,961

See accompanying “Notes to Consolidated Financial Statements.”

Consolidated Balance Sheets

Hawaiian Electric Company, Inc. and Subsidiaries

December 31	2003			2002
(in thousands)
Assets
Utility plant, at cost
Land	$	29,627		$	29,403
Plant and equipment		3,306,128			3,187,311
Less accumulated depreciation		(1,290,929	)		(1,205,336	)
Plant acquisition adjustment, net		249			302
Construction in progress		195,295			164,300
Net utility plant		2,240,370			2,175,980
Current assets
Cash and equivalents		158			1,726
Customer accounts receivable, net		91,999			87,113
Accrued unbilled revenues, net		60,372			60,098
Other accounts receivable, net		2,333			2,213
Fuel oil stock, at average cost		43,612			35,649
Materials and supplies, at average cost		21,233			19,450
Prepayments and other		86,763			75,610
Total current assets		306,470			281,859
Other assets
Unamortized debt expense		14,035			13,354
Long-term receivables and other		20,381			22,243
Total other assets		34,416			35,597
	$	2,581,256		$	2,493,436
Capitalization and liabilities
Capitalization (see Consolidated Statements of Capitalization)
Common stock equity	$	944,443		$	923,256
Cumulative preferred stock, not subject to mandatory redemption		34,293			34,293
HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO and HECO-guaranteed debentures		100,000			100,000
Long-term debt, net		699,420			705,270
Total capitalization		1,778,156			1,762,819
Current liabilities
Short-term borrowings-affiliate		6,000			5,600
Accounts payable		72,377			59,992
Interest and preferred dividends payable		11,303			11,532
Taxes accrued		93,303			79,133
Other		34,015			28,020
Total current liabilities		216,998			184,277
Deferred credits and other liabilities
Deferred income taxes		170,841			158,367
Regulatory liabilities		71,882			57,050
Unamortized tax credits		47,066			47,985
Other		62,344			64,844
Total deferred credits and other liabilities		352,133			328,246
Contributions in aid of construction		233,969			218,094
	$	2,581,256		$	2,493,436

See accompanying “Notes to Consolidated Financial Statements.”

2

Consolidated Statements of Capitalization

Hawaiian Electric Company, Inc. and Subsidiaries

December 31	2003		2002		2001
(dollars in thousands, except per share amounts)
Common stock equity
Common stock of $6 2/3 par value
Authorized: 50,000,000 shares. Outstanding: 2003, 2002 and 2001, 12,805,843 shares	$	85,387	$	85,387	$	85,387
Premium on capital stock		295,841		295,846		295,806
Retained earnings		563,215		542,023		495,961
Common stock equity		944,443		923,256		877,154
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: 2003 and 2002, 1,234,657 shares.

Series	Par Value				Shares Outstanding December 31, 2003	2003		2002
(dollars in thousands, except par value and shares outstanding)
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.”

3

Consolidated Statements of Capitalization, continued

Hawaiian Electric Company, Inc. and Subsidiaries

December 31	2003		2002
(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
Obligations to the State of Hawaii for the repayment of Special Purpose Revenue Bonds:
HECO, 5.00%, refunding series 2003B, due 2022		40,000		—
HELCO, 5.00%, refunding series 2003B, due 2022		12,000		—
HELCO, 4.75%, refunding series 2003A, due 2020		14,000		—
HECO, 5.10%, series 2002A, due 2032		40,000		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
HELCO, 6.55%, series 1992, due 2022		—		12,000
MECO, 6.55%, series 1992, due 2022		—		8,000
HELCO, 7 3/8%, series 1990C, due 2020		—		10,000
HELCO, 7.60%, series 1990B, due 2020		—		4,000
		717,900		725,900
Less funds on deposit with trustees		14,013		16,111
Total obligations to the State of Hawaii		703,887		709,789
Less unamortized discount		4,467		4,519
Long-term debt, net		699,420		705,270
Total capitalization	$	1,778,156	$	1,762,819

See accompanying “Notes to Consolidated Financial Statements.”

4

Consolidated Statements of Cash Flows

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31	2003			2002			2001
(in thousands)
Cash flows from operating activities
Income before preferred stock dividends of HECO	$	79,991		$	91,285		$	89,380
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Depreciation of utility plant		110,560			105,424			100,714
Other amortization		8,232			11,376			12,740
Deferred income taxes		12,519			12,818			8,557
Tax credits, net		585			1,031			2,476
Allowance for equity funds used during construction		(4,267	)		(3,954	)		(4,239	)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable		(5,006	)		(4,802	)		9,448
Decrease (increase) in accrued unbilled revenues		(274	)		(7,475	)		11,397
Decrease (increase) in fuel oil stock		(7,963	)		(11,209	)		12,684
Decrease (increase) in materials and supplies		(1,783	)		252			(2,915	)
Increase in regulatory assets, net		(4,897	)		(1,881	)		(4,036	)
Increase (decrease) in accounts payable		12,385			6,026			(17,732	)
Increase (decrease) in taxes accrued		14,170			(6,925	)		7,872
Other		(8,196	)		(20,389	)		(27,597	)
Net cash provided by operating activities		206,056			171,577			198,749
Cash flows from investing activities
Capital expenditures		(146,964	)		(114,558	)		(115,540	)
Contributions in aid of construction		12,963			11,042			10,958
Proceeds from sales of assets		118			56			—
Net cash used in investing activities		(133,883	)		(103,460	)		(104,582	)
Cash flows from financing activities
Common stock dividends		(57,719	)		(44,143	)		(36,309	)
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		67,935			35,275			17,336
Repayment of long-term debt		(74,000	)		(5,000	)		—
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		400			(42,697	)		(61,869	)
Repayment of other short-term borrowings		—			—			(3,000	)
Other		(1,602	)		(2,929	)		(1,246	)
Net cash used in financing activities		(73,741	)		(68,249	)		(93,843	)
Net increase (decrease) in cash and equivalents		(1,568	)		(132	)		324
Cash and equivalents, January 1		1,726			1,858			1,534
Cash and equivalents, December 31	$	158		$	1,726		$	1,858

See accompanying “Notes to Consolidated Financial Statements.”

5

Notes to Consolidated Financial Statements

Hawaiian Electric Company, Inc. and Subsidiaries

1. Summary of significant accounting policies

General

Hawaiian Electric Company, Inc. (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 on all major islands in Hawaii other than Kauai, and are regulated by the Public Utilities Commission of the State of Hawaii (PUC). HECO also owns non-regulated subsidiaries: Renewable Hawaii, Inc. (RHI), which will invest in renewable energy projects; HECO Capital Trust I and HECO Capital Trust II, which are financing entities; and HECO Capital Trust III, which was formed in November 2003 in connection with a possible future financing.

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 property, plant and equipment; pension and other postretirement benefit obligations; contingencies and litigation; income taxes; regulatory assets and liabilities; and revenues.

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

Utility plant

Utility plant is reported at cost. Self-constructed plant includes engineering, supervision, 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 is charged to accumulated depreciation. Amounts collected from customers for cost of removal (expected to exceed salvage value in the future) are included in regulatory liabilities.

6

Depreciation

Depreciation is computed primarily using the straight-line method over the estimated useful lives of the assets being depreciated. 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 2003, 2002 and 2001.

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 utility plant. The PUC requires the Company to fund its pension and postretirement benefit costs. The Company’s policy is to fund pension costs in amounts that will not be less than the minimum funding requirements of the Employee Retirement Income Security Act of 1974 and will not exceed the maximum tax-deductible amounts. The Company generally funds at least the net periodic pension cost as calculated using SFAS No. 87 during the fiscal year, subject to statutory funding limits and targeted funded status as determined with the consulting actuary. Certain health care and/or life insurance benefits are provided to eligible retired employees and the employees’ beneficiaries and covered dependents. The Company generally funds the net periodic postretirement benefit costs other than pensions as calculated using SFAS No. 106 and the amortization of the regulatory asset for postretirement benefits other than pensions, while maximizing the use of the most tax advantaged funding vehicles, subject to statutory funding limits, cash flow requirements and reviews of the funded status with the consulting actuary.

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.

7

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 meter readings in the beginning of the following month, 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, 2003, customer accounts receivable include unbilled energy revenues of $60 million on a base of annual revenue of $1.4 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 2003 and 2001, the Company included $123 million and $114 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense. 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 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. If a project under construction is delayed for an extended period of time, AFUDC may be stopped.

The weighted-average AFUDC rate was 8.7% in 2003, 2002 and 2001, 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 investment tax credits are deferred and amortized over the estimated useful lives of the properties which qualified for the credits.

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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.

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.

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. 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 June 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),” which required companies to recognize costs associated with exit or disposal activities at the date of a commitment to an exit or disposal plan. SFAS No. 146 replaces EITF Issue No. 94-3. The Company adopted the provisions of SFAS No. 146 on January 1, 2003. Since SFAS No. 146 applies prospectively to exit or disposal activities initiated after December 31, 2002, the adoption of SFAS No. 146 had no effect on the Company’s historical financial statements.

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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 with respect to the obligations of third parties who are not consolidated in its financial statements. FIN No. 45 also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken. The Company adopted the provisions of FIN No. 45 on January 1, 2003. Since the initial recognition and measurement provisions of FIN No. 45 are applied prospectively to guarantees issued or modified after December 31, 2002, and since HECO and its subsidiaries have not guaranteed the obligations of any entity or person not included in the Company’s consolidated financial statements, the adoption of these provisions of FIN No. 45 had no effect on the Company’s consolidated historical financial statements.

Consolidation of variable interest entities (VIEs). In December 2003, the FASB issued revised FIN No. 46 (FIN No. 46R), “Consolidation of Variable Interest Entities,” which addresses how a business enterprise should evaluate whether it has a controlling financial interest in an entity through means other than voting rights and accordingly should consolidate the entity. FIN No. 46R replaces FIN No. 46, which was issued in January 2003. The Company was required to apply FIN No. 46 immediately to variable interests in VIEs created after January 31, 2003. For variable interests in VIEs created before February 1, 2003, FIN No. 46 was to be applied no later than the end of the first reporting period ending after December 15, 2003. The disclosures required by FIN No. 46 relating to HECO-obligated trust preferred securities are included in Note 3 and relating to independent power producers (IPPs) are discussed in Note 11. The Company adopted the provisions (other than the already adopted disclosure provisions) of FIN No. 46 relating to VIEs created before February 1, 2003 as of December 31, 2003 with no effect on the Company’s financial statements.

The Company is evaluating the impact of applying FIN No. 46R in the first quarter of 2004 to the grantor trusts that have issued preferred securities (i.e., existing VIEs in which the Company has variable interests) and has not yet completed this analysis. At this time, it is anticipated that the Company will deconsolidate the trusts that have issued trust preferred securities, as discussed in Note 3, since the Company may not be the primary beneficiary of such trusts. This deconsolidation will result in the Company reflecting $3.1 million in investment in unconsolidated subsidiaries and $103.1 million of long-term debt payable to the trusts, rather than $100.0 million in trust preferred securities in the Consolidated Balance Sheets. Under this treatment, the Company will also record $7.9 million in interest expense and approximately $0.2 million in equity in net income of unconsolidated subsidiaries, rather than $7.7 million in preferred securities distributions of trust subsidiaries in the Consolidated Statements of Income for 2004. Further, the Company is evaluating the impact of applying FIN No. 46R in the first quarter of 2004 to the relationships with IPPs from whom the Company purchases power and has not yet completed this analysis. A possible outcome of the analysis, however, is that the HECO (or its subsidiaries, as applicable) may be found to meet the definition of a primary beneficiary of the IPPs, which finding may result in the consolidation of the IPPs in the Company’s consolidated financial statements. The consolidation of IPPs would have a material effect on the Company’s consolidated financial statements, including the recognition of a significant amount of assets and liabilities.

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

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

Retirement benefits. In December 2003, the FASB issued SFAS No. 132 (revised), “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” which prescribes employers’ disclosures about pension and other postretirement benefit plans, but does not change the measurement or recognition of those plans. SFAS No. 132 (revised) retains and revises the disclosure requirements contained in the original SFAS No. 132 and also requires additional disclosures about the assets, obligations, cash flows, and net periodic benefit cost of defined benefit pension and other postretirement benefit plans. The disclosures required under SFAS No. 132 (revised) for 2003 are included in Note 10.

Reclassifications

Certain reclassifications have been made to prior years’ financial statements to conform to the 2003 presentation. For example, the accrual for cost of removal (expected to exceed salvage value in the future) of $163 million as of December 31, 2002 has been reclassified from accumulated depreciation to regulatory liabilities.

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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 payment of the following prices in the event of voluntary liquidation or redemption:

December 31, 2003	Voluntary Liquidation Price		Redemption Price
Series
C, D, E, H, J and K (HECO)	$	20	$	21
I (HECO)		20		20
G (HELCO)		100		100
H (MECO)		100		100

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

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

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

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

HECO Capital Trust I (Trust I) exists for the exclusive purposes of (i) issuing in 1997 trust securities, consisting of 8.05% Cumulative Quarterly Income Preferred Securities, Series 1997 (1997 Trust Preferred Securities) ($50 million) and trust common securities ($1.5 million to HECO), (ii) investing the proceeds of the trust securities in 8.05% Junior Subordinated Deferrable Interest Debentures, Series 1997 (1997 Debentures) issued by HECO in the principal amount of $31.5 million and issued by each of MECO and HELCO in the respective principal amounts of $10 million, (iii) making distributions on the 1997 Trust Preferred Securities and trust common securities and (iv) engaging in only those other activities necessary or incidental thereto. The 1997 Debentures, together with the obligations of HECO, MECO and HELCO under an expense agreement and HECO’s obligations under its trust guarantee and its guarantee of the obligations of MECO and HELCO under their respective debentures, are the sole assets of Trust I.

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

See note 16 for financial information of Trust I and Trust II.

4. Long-term debt

For special purpose revenue bonds, 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.

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 and were redeemed in March 2003.

In June 2003, HELCO’s 7.6% Series 1990B and 7 ³/8% Series 1990C Special Purpose Revenue Bonds were refunded with the proceeds from the 4.75% Refunding Series 2003A Special Purpose Revenue Bonds loaned to HELCO ($14 million). In addition, HECO’s and HELCO’s proportionate share of the 6.55% Series 1992 Special Purpose Revenue Bonds were refunded with the proceeds from the 5.00% Refunding Series 2003B Special Purpose Revenue Bonds that were loaned to HECO ($40 million) and HELCO ($12 million). The redemption premium on refunding the Series 1992 Special Purpose Revenue Bonds was paid proportionately by HECO and HELCO and was recorded as a regulatory asset and is being amortized against income over the remaining term of the refunded bonds.

At December 31, 2003, the aggregate payments of principal required on long-term debt during the next five years are nil in each year.

5. Short-term borrowings

There were no short-term borrowings from nonaffiliates at December 31, 2003 or 2002.

At December 31, 2003 and 2002, the Company maintained bank lines of credit which totaled $90 million ($50 million maturing in April 2004, $10 million maturing in May 2004 and $30 million maturing in June 2004) and $100 million, respectively. HECO maintains these lines of credit (at a base rate [Prime, Fed Funds, Bank Base, Bank Quoted, Eurodollar or LIBOR rate] plus a margin ranging from 0 to 80 basis points) 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 during 2003 and 2002.

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6. Regulatory assets and liabilities

In accordance with SFAS No. 71, HECO and its subsidiaries’ financial statements reflect assets, liabilities, revenues and expenses based on current cost-based rate-making regulations. Their continued accounting under SFAS No. 71 generally requires that rates are established by an independent, third-party regulator; rates are designed to recover the costs of providing service; and it is reasonable to assume that rates can be charged to and collected from customers. Management believes HECO and its subsidiaries’ operations currently satisfy the SFAS No. 71 criteria. If events or circumstances should change so that those criteria are no longer satisfied, the Company expects that the regulatory liabilities, net of regulatory assets, would be credited to income. In the event of unforeseen regulatory actions or other circumstances, however, management believes that a material adverse effect on the Company’s results of operations and financial position may result if regulatory assets have to be charged to expense without an offsetting credit from regulatory liabilities.

Regulatory liabilities represent costs expected to be incurred in the future (period noted in parenthesis). Regulatory assets represent deferred costs expected to be fully recovered through rates over PUC authorized periods ranging from one to 36 years (period noted in parenthesis). Regulatory assets and liabilities were as follows:

December 31	2003			2002
(in thousands)
Cost of removal in excess of salvage value (1 to 50 years)	$	(178,424	)	$	(162,618	)
Income taxes, net (1 to 36 years)		66,129			64,278
Postretirement benefits other than pensions (10 years)		16,108			17,897
Unamortized expense and premiums on retired debt and equity issuances (2 to 26 years)		12,148			11,005
Integrated resource planning costs, net (1 year)		2,731			1,965
Vacation earned, but not yet taken (1 year)		4,750			4,776
Other (1 to 5 years)		4,676			5,647
	$	(71,882	)	$	(57,050	)

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 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 2002. MECO has been allowed to recover its deferred IRP costs for years 1995 through 2002, and is currently recovering costs incurred for year 2002. 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, 2003, the aggregate amount of revenues recorded by all three companies to recover deferred IRP costs, which are subject to refund with interest, amounted to $16.6 million.

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7. Income taxes

The components of income taxes charged to operating expenses were as follows:

December 31	2003			2002			2001
(in thousands)
Federal:
Current	$	32,167		$	37,481		$	41,120
Deferred		13,171			13,337			8,584
Deferred tax credits, net		(1,504	)		(1,557	)		(1,567	)
		43,834			49,261			48,137
State:
Current		4,828			5,369			3,272
Deferred		928			1,068			1,549
Deferred tax credits, net		585			1,031			2,476
		6,341			7,468			7,297
Total	$	50,175		$	56,729		$	55,434

Income tax benefits related to nonoperating activities, included in “Other, net” on the consolidated statements of income, amounted to $351,000, $71,000 and $18,000 for 2003, 2002 and 2001, 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	2003			2002			2001
(in thousands)
Amount at the federal statutory income tax rate	$	46,235		$	52,226		$	51,005
State income taxes on operating income, net of effect on federal income taxes		4,121			4,854			4,743
Other		(181	)		(351	)		(314	)
Income taxes charged to operating expenses	$	50,175		$	56,729		$	55,434

The tax effects of book and tax basis differences that give rise to deferred tax assets and liabilities were as follows:

December 31	2003		2002
(in thousands)
Deferred tax assets:
Cost of removal in excess of salvage value	$	69,425	$	63,275
Contributions in aid of construction and customer advances		42,179		46,052
Other		13,633		13,213
		125,237		122,540
Deferred tax liabilities:
Property, plant and equipment		238,006		225,306
Regulatory assets, excluding amounts attributable to property, plant and equipment		25,514		24,794
Other		32,558		30,807
		296,078		280,907
Net deferred income tax liability	$	170,841	$	158,367

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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 2003, 2002 and 2001.

8. Cash flows

Supplemental disclosures of cash flow information

Cash paid for interest (net of AFUDC-Debt) and income taxes was as follows:

Years ended December 31	2003		2002		2001
(in thousands)
Interest	$	41,601	$	41,701	$	43,519
Income taxes	$	36,316	$	47,530	$	38,392

Supplemental disclosures of noncash activities

The allowance for equity funds used during construction, which was charged primarily to construction in progress, amounted to $4.3 million, $4.0 million and $4.2 million in 2003, 2002 and 2001, respectively.

The estimated fair value of noncash contributions in aid of construction amounted to $13.9 million, $4.4 million and $2.4 million in 2003, 2002 and 2001, 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 received approximately 10% ($135 million), 9% ($119 million) and 10% ($127 million) of their operating revenues from the sale of electricity to various federal government agencies in 2003, 2002 and 2001, respectively.

10. Retirement benefits

Pensions. Substantially all of the employees of HECO, HELCO and MECO participate in the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries. The Plan is a qualified, non-contributory defined benefit pension plan and includes benefits for union employees determined in accordance with the terms of the collective bargaining agreements between the utilities 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 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. The Directors’ Plan has been frozen since 1996, and no participants have accrued any benefits after that time. The plan will be terminated at the time all remaining benefits have been paid.

Each participating employer reserves the right to terminate its participation in the applicable plans 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

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exist would be paid to the Participating Employers. Participants’ benefits in the Plans are covered up to certain limits under insurance provided by the Pension Benefit Guaranty Corporation.

The Participating Employers contribute amounts to a master pension trust for the Plan in accordance with the funding requirements of ERISA and considering the deductibility of contributions under the Internal Revenue 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 HECO, HELCO and MECO under the Plan and the Supplemental/Excess/Directors Plans, it is necessary to make complex calculations and estimates based on numerous assumptions, including the 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. Health benefits are also provided to dependents of eligible employees. The contribution for health benefits paid by the participating employers is based on retirees’ years of service and retirement dates. Generally, employees are eligible for these benefits if, upon retirement from active employment, they are eligible to receive benefits from the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries.

Among other provisions, the plan provides prescription drug benefits for Medicare-eligible participants who retire after 1998. Retirees who are eligible for the drug benefits are required to pay a portion of the cost each month.

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was signed into law. The Act introduces a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare benefit. The Act may have the impact of reducing plan liabilities and future net periodic postretirement benefit cost. For example, some participants may elect to opt out of the plan and participate instead in the Medicare drug plan. In such case, the plan would have no further liabilities to provide benefits for such participants. Plan amendments taking the Medicare drug benefits into account could also reduce plan liabilities and net periodic cost. In accordance with FASB’s Staff Position No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” the Company has elected to defer recognition of the effects of the Act in any measures of the benefit obligation or cost. Specific authoritative guidance on the accounting for the federal subsidy is pending and that guidance, when issued, could require the Company to change previously reported information.

The postretirement benefits other than pensions 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 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 Company’s balance sheet were as follows:

	Pension benefits						Other benefits
(in thousands)	2003			2002			2003			2002
Benefit obligation, January 1	$	662,289		$	591,036		$	155,638		$	143,055
Service cost		18,899			16,965			3,475			3,028
Interest cost		43,552			41,891			10,161			9,920
Actuarial loss		59,676			46,578			13,788			6,004
Benefits paid		(35,391	)		(34,181	)		(7,061	)		(6,369	)
Benefit obligation, December 31		749,025			662,289			176,001			155,638
Fair value of plan assets, January 1		551,967			677,590			74,534			88,448
Actual return (loss) on plan assets		124,885			(91,778	)		18,865			(13,927	)
Employer contribution		20,383			328			10,215			6,382
Benefits paid		(35,554	)		(34,173	)		(7,116	)		(6,369	)
Fair value of plan assets, December 31		661,681			551,967			96,498			74,534
Funded status		(87,344	)		(110,322	)		(79,503	)		(81,104	)
Unrecognized net actuarial loss		173,028			185,270			26,103			23,604
Unrecognized net transition obligation		8			960			29,378			32,642
Unrecognized prior service gain		(7,281	)		(8,031	)		—			—
Net amount recognized, December 31	$	78,411		$	67,877		$	(24,022	)	$	(24,858	)
Amounts recognized in the balance sheet consist of:
Prepaid benefit cost	$	81,513		$	70,635		$	—		$	—
Accrued benefit liability		(3,102	)		(2,758	)		(24,022	)		(24,858	)
Net amount recognized, December 31	$	78,411		$	67,877		$	(24,022	)	$	(24,858	)

The defined benefit pension plans’ accumulated benefit obligations as of December 31, 2003 and 2002 were $630 million and $552 million, respectively. Depending on the performance of the pension plan assets, the status of interest rates and numerous other factors, the Company could be required to recognize an additional minimum liability as prescribed by SFAS No. 87, “Employers’ Accounting for Pensions,” in the future. If recognizing a liability is required, the liability would largely be recorded as a reduction to stockholders’ equity through a non-cash charge to accumulated other comprehensive income, and would result in the removal of the prepaid pension asset ($82 million and $70 million as of December 31, 2003 and 2002, respectively) from the Company’s balance sheet.

The measurement dates used to determine pension and other postretirement benefit measurements for the defined benefit plans were December 31, 2003, 2002 and 2001.

The weighted-average asset allocation of pension and other postretirement benefit defined benefit plans was as follows:

	Pension benefits								Other benefits
					Investment policy								Investment policy
December 31	2003		2002		Target		Range		2003		2002		Target		Range
Asset category
Equity securities	76	%	69	%	74	%	67-80	%	77	%	71	%	75	%	70-80	%
Debt securities	22		29		25		20-30	%	22		28		25		20-30	%
Other	2		2		1		0-3	%	1		1		—		—
	100	%	100	%	100	%			100	%	100	%	100	%

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A primary goal of the plans is to achieve long-term asset growth sufficient to pay future benefit obligations at a reasonable level of risk. The investment policy target for pension and other postretirement benefit defined benefit plans reflects the philosophy that long-term growth can best be achieved by prudent investments in equity securities while balancing overall fund volatility by an appropriate allocation to fixed income securities. In order to reduce the level of portfolio risk and volatility in returns, efforts have been made to diversify the plans investments by asset class, geographic region, market capitalization and investment style.

The expected long-term rate of return assumption was based on an asset/liability study performed by the plans’ actuarial and investment consultants, which projected the return over the long term to be in excess of 9%, based on the target asset allocation.

HECO and its subsidiaries’ current estimate of contributions to the retirement benefit plans in 2004 is $11 million.

The following weighted-average assumptions were used in the accounting for the plans:

	Pension benefits						Other benefits
December 31	2003		2002		2001		2003		2002		2001
Benefit obligation
Discount rate	6.25	%	6.75	%	7.25	%	6.25	%	6.75	%	7.25	%
Expected return on plan assets	9.0		9.0		10.0		9.0		9.0		10.0
Rate of compensation increase	4.6		4.6		4.6		4.6		4.6		4.6
Net periodic benefit cost (years ended)
Discount rate	6.75		7.25		7.5		6.75		7.25		7.5
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, 2003, the assumed health care trend rates for 2004 and future years were as follows: medical, 10.00%, grading down to 4.25%; dental, 4.25%; and vision, 3.25%. 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%.

The components of net periodic benefit cost (return) were as follows:

	Pension benefits									Other benefits
Years ended December 31	2003			2002			2001			2003			2002			2001
(in thousands)
Service cost	$	18,899		$	16,965		$	16,317		$	3,475		$	3,028		$	2,951
Interest cost		43,553			41,891			40,073			10,161			9,920			9,128
Expected return on plan assets		(55,678	)		(76,169	)		(75,644	)		(7,521	)		(9,872	)		(9,882	)
Amortization of unrecognized transition obligation		952			2,263			2,273			3,264			3,264			3,264
Amortization of prior service gain		(750	)		(750	)		(750	)		—			—			—
Recognized actuarial loss (gain)		2,873			(3,683	)		(8,210	)		—			(716	)		(2,597	)
Net periodic benefit cost (return)	$	9,849		$	(19,483	)	$	(25,941	)	$	9,379		$	5,624		$	2,864

Of the net periodic pension benefit costs/returns, the Company recorded expense of $7 million in 2003 and income of $14 million in 2002 and $19 million in 2001, and charged or credited the remaining amounts primarily to electric utility plant. Of the net periodic other than pension benefit costs, the Company expensed $7 million, $4 million and $2 million in 2003, 2002 and 2001, 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 $3 million, $3 million and nil, respectively, as of December 31, 2003 and $3 million, $2 million and nil, respectively, as of December 31, 2002.

The health care cost trend rate assumptions can have a significant effect on the amounts reported for other benefits. At December 31, 2003, a one-percentage-point increase in the assumed health care cost trend rates

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would have increased the total service and interest cost by $0.3 million and the postretirement benefit obligation by $3.5 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 $4.3 million.

11. Commitments and contingencies

Fuel contracts

HECO and its subsidiaries have contractual agreements to purchase minimum quantities of fuel oil and diesel fuel through December 31, 2004 (at prices tied to the market prices of petroleum products in Singapore and Los Angeles). New fuel contracts are currently being negotiated. Based on the average price per barrel at January 1, 2004, the estimated cost of minimum purchases under the fuel supply contracts for 2004 is $350 million. The actual cost of purchases in 2004 could vary substantially from this estimate as a result of changes in market prices, quantities actually purchased and/or other factors. The Company purchased $390 million, $317 million and $328 million of fuel under contractual agreements in 2003, 2002 and 2001, respectively.

Power purchase agreements (PPAs)

At December 31, 2003, HECO and its subsidiaries had seven PPAs for a total of 534 megawatts (MW) of firm capacity. Of the 534 MW of firm capacity under PPAs, approximately 79% is under PPAs with AES Hawaii, Inc. (since March 1988), Kalaeloa Partners, L.P. (since October 1988) and Hamakua Energy Partners, L.P. (since October 1997). The primary business activities of these IPPs are the generation and sale of power to HECO and its subsidiaries. Financial information about the size of these IPPs is not currently available. Purchases from all IPPs totaled $368 million, $326 million and $338 million for 2003, 2002 and 2001, respectively. The PUC allows rate recovery for energy and firm capacity payments to IPPs under these agreements. Assuming that each of the agreements remains in place for its current term and the minimum availability criteria in the PPAs are met, aggregate minimum fixed capacity charges are expected to be approximately $123 million in 2004, $118 million each in 2005, 2006 and 2007, $116 million in 2008, and a total of $1.5 billion in the period from 2009 through 2030.

In general, HECO and its subsidiaries base their payments under the PPAs 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, 2003, HECO and its subsidiaries had recognized $16.6 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

After several years of opposition to, and resulting delays in, the efforts of HELCO to expand its Keahole power plant site to add new generation, HELCO entered into a conditional settlement agreement in November of 2003 (Settlement Agreement) with all but one of the parties (Waimana Enterprises, Inc. (Waimana) which had actively opposed the project) and with several regulatory agencies. The settlement agreement is intended to permit HELCO to complete the plant expansion, subject to satisfaction of the terms and conditions of the Settlement Agreement, and HELCO is actively engaged in construction activities to install the planned generation. Two 20 MW combustion turbines (CT-4 and CT-5) are currently expected to be ready for initial operation in the second quarter of 2004 and fully operational by the end of 2004.

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The following is a summary of the status of HELCO’s efforts to obtain certain of the permits required for the Keahole expansion project and related proceedings that have impeded and delayed HELCO’s efforts to construct the plant, a description of the Settlement Agreement and its implementation to date and a discussion (under “Management’s evaluation; costs incurred”) of the potential financial statement implications of this project.

Historical context. In 1991, HELCO began planning to meet increased electric generation demand forecast for 1994. HELCO’s plans were to install at its Keahole power plant CT-4 and CT-5, followed by an 18 MW heat steam recovery generator (ST-7), at which time these units would be converted to a 56 MW (net) dual-train combined-cycle unit. In January 1994, the PUC approved expenditures for CT-4, which HELCO had planned to install in late 1994. In 1995, the PUC allowed HELCO to pursue construction of and commit expenditures for CT-5 and ST-7, but noted in its decision that such costs are not to be included in rate base until the project is installed and “is used and useful for utility purposes.” The PUC at that time also ordered HELCO to continue negotiating with IPPs that had proposed generating facilities that they claimed would be a substitute for HELCO’s planned expansion of the Keahole plant, stating that the facility to be built should be the one that can be most expeditiously put into service at “allowable cost.”

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

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

The Enserch and HCPC complaints were resolved by HELCO’s entry into PPAs with each of these parties. The PPA with HCPC by its terms expires in December 2004 (subject to early termination or extensions). Due to subsequent developments, including a ruling by the Hawaii Circuit Court for the Third Circuit (Third Circuit Court) that the lease for KCP’s proposed plant site was invalid, HELCO believes that KCP’s proposal for a PPA is not viable.

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

Land use permit amendment and related proceedings. The Third Circuit Court ruled in 1997 that, because the BLNR had failed to render a valid decision on HELCO’s application to amend its land use permit before the statutory deadline in April 1996, HELCO was entitled to use its Keahole site for the expansion project (HELCO’s “default entitlement”). The Third Circuit Court’s 1998 final judgment on this issue was appealed to the Hawaii Supreme Court by several parties. On July 8, 2003, the Hawaii Supreme Court issued its opinion affirming the Third Circuit Court’s final judgment on the basis that the BLNR failed to render the necessary four votes either approving or rejecting HELCO’s application.

While the Hawaii Supreme Court’s July 2003 decision validated the Third Circuit Court’s 1998 final judgment confirming HELCO’s default entitlement, construction of the expansion project had been delayed for much of the intervening period that had followed the 1998 final judgment, first because HELCO had not yet obtained its final air permit and then because of other rulings made by the Third Circuit Court in several related proceedings.

The Third Circuit Court’s 1998 final judgment confirming HELCO’s default entitlement provided that HELCO must comply with the conditions in its application and with the standard land use conditions insofar as those

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conditions were not inconsistent with the default entitlement. Numerous proceedings were commenced before the Third Circuit Court and the BLNR in which parties opposed to the project claimed that HELCO had not or could not comply with the conditions applicable to its default entitlement. The Third Circuit Court issued a number of rulings in these proceedings which further delayed or otherwise adversely affected HELCO’s ability to construct and efficiently operate CT-4 and CT-5. These rulings have now been, or are expected to be, resolved under the terms of the Settlement Agreement, as follows:

• Based on a change by the DOH in its interpretation of the noise rules it promulgated under the Hawaii Noise Pollution Act, the Third Circuit Court ruled that a stricter noise standard applied to HELCO’s Keahole plant. HELCO filed a separate complaint for declaratory relief against the DOH seeking the invalidation of the noise rules on constitutional and other grounds. The Third Circuit Court ruled against HELCO in that separate complaint, and HELCO appealed the Third Circuit Court’s final judgment to this effect (Noise Standards Judgment) in August 1999. In the Settlement Agreement, HELCO agrees that the Keahole plant will comply during normal operations with the stricter noise standards and that it will not begin full-time operations of CT-4 and CT-5 until it has installed noise mitigation equipment to meet these standards. In accordance with the Settlement Agreement, on January 6, 2004, the parties filed a stipulation to dismiss HELCO’s appeal of the Noise Standards Judgment.

• In other litigation in the Third Circuit Court brought by Keahole Defense Coalition (KDC) and two individuals (Individual Plaintiffs), the Third Circuit Court denied plaintiff’s motions made on several grounds to enjoin construction of the Keahole plant and plaintiffs appealed these rulings to the Hawaii Supreme Court in June 2002. Pursuant to the Settlement Agreement, on January 6, 2004, KDC filed a motion in the Hawaii Supreme Court to dismiss this appeal.

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

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

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

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

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

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

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

• On November 5, 2003, Waimana filed a complaint in the United States District Court for the District of Hawaii in which it sought, among other things, a temporary restraining order enjoining the Third Circuit Court from granting the motion to vacate the November 2002 Final Judgment. The United States District Court denied this motion on November 7, 2003 and dismissed Waimana’s complaint on November 14, 2003.

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

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

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

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

Since the time construction activities resumed in November 2003, HELCO has laid the groundwork for implementation of many of its commitments under the Settlement Agreement. However, despite the numerous rulings against Waimana described above, it has continued to pursue efforts to stop or delay the Keahole project and to interfere with implementation of the Settlement Agreement, including (a) filing a notice of appeal to the Hawaii Supreme Court of the Third Circuit Court’s November 2003 Final Judgment (vacating the November 2002 Final Judgment), (b) appealing to the Third Circuit Court the BLNR 2003 Construction Period Extension and (c) appealing to the Third Circuit Court the BLNR’s approval, on December 12, 2003, of HELCO’s request for a revocable permit to use brackish well water as the primary source of water for operating the Keahole plant. In January 2004, the Third Circuit Court denied Waimana’s motion to stay the effectiveness of the BLNR 2003 Construction Period Extension, and granted HELCO’s motion (joined in by the BLNR) to dismiss Waimana’s appeal of that extension. In February 2004, the Third Circuit Court denied Waimana’s motion to stay the effectiveness of the revocable permit to use brackish water, and granted HELCO’s motion (joined in by the BLNR) to dismiss Waimana’s appeal of that permit.

Land Use Commission petition. After previously submitting and withdrawing a petition, HELCO submitted to the Hawaii State Land Use Commission (LUC) on November 25, 2003 a new petition to reclassify the Keahole plant site from conservation land use to urban land use. The installation of ST-7, with SCR as contemplated by the Settlement Agreement, is dependent upon this reclassification. In December 2003, Waimana filed a Notice of Intent to Intervene in the LUC proceeding. On February 5, 2004, the LUC issued an order, with which HELCO concurred, that an environmental impact statement (EIS) be prepared in connection with its reclassification petition. Work on the EIS was already in progress before the ruling was issued. The entire reclassification process could take several years.

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Management’s evaluation; costs incurred. The probability that HELCO will be allowed to complete the installation of CT-4 and CT-5 during 2004 has been substantially enhanced by the Settlement Agreement, the Third Circuit’s November 2003 Final Judgment, and the decisions of the BLNR to extend the construction deadline by 19 months from December 31, 2003 and to grant to HELCO a revocable permit to use brackish water for the plant. Although additional steps must be completed under the Settlement Agreement to satisfy its remaining conditions and HELCO must obtain the further permits necessary to complete installation of CT-4 and CT-5 (and, eventually ST-7), management believes that the prospects are good that those conditions will be satisfied and that any further necessary permits will be obtained. Nevertheless, Waimana has continued its efforts to stop or delay the construction and there could be further delays in completing construction. In the meantime, HELCO’s management remains concerned with the condition and performance of certain aging generators on the HELCO system, which were intended to be retired or to be operated less frequently once CT-4 and CT-5 were installed, as well as the current operating status of various IPPs, which provide approximately 43% of HELCO’s generating capacity under power purchase agreements. A related 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. HELCO is continuing its efforts to avert power interruptions, but there can be no assurance that power interruptions will not occur.

Based on management’s expectation that the remaining conditions under the Settlement Agreement will be satisfied, HELCO recorded as expenses in November 2003 approximately $3.1 million of legal fees and other costs required to be paid under the Settlement Agreement. If the Settlement Agreement is implemented and ST-7 is installed, HELCO will have incurred approximately $21 million of capital expenditures relating to noise mitigation, visual mitigation and air pollution control at the Keahole power plant site (approximately $8 million for CT-4 and CT-5, approximately $9 million for ST-7, when installed, and approximately $4 million for other existing units). Other miscellaneous incidental expenses may also be incurred.

As of December 31, 2003, HELCO’s costs incurred in its efforts to put CT-4 and CT-5 into service and to support existing units (excluding costs the PUC permitted to be transferred to plant-in-service for pre-air permit facilities) amounted to approximately $84 million, including $32 million for equipment and material purchases, $32 million for planning, engineering, permitting, site development and other costs and $20 million for AFUDC up to November 30, 1998, after which date management decided not to continue to accrue AFUDC in light of the delays that had been experienced, even though management believes that it has acted prudently with respect to the Keahole project. Substantial additional costs, currently estimated to be approximately $15 million, will be required in order to complete the installations of CT-4 and CT-5, including the costs necessary to satisfy the requirements of the Settlement Agreement pertaining to those units. HELCO’s plans for ST-7 are pending until it obtains the contemplated reclassification of the Keahole plant site from conservation to urban and necessary permits, which HELCO has agreed to seek promptly. The costs of ST-7 will be higher than originally planned, not only by reason of the change in schedule in its installation, but also by reason of additional costs that will be incurred to satisfy the requirements of the Settlement Agreement.

The recovery of costs relating to CT-4 and CT-5 is subject to the rate-making process governed by the PUC. Management believes no adjustment to costs incurred to put CT-4 and CT-5 into service is required as of December 31, 2003. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HELCO may be required to write off a material portion of the costs incurred in its efforts to put these units into service whether or not CT-4 and CT-5 are installed.

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Oahu transmission system

HECO’s power sources are located primarily in West Oahu, but the bulk of HECO’s system load is in the Honolulu/East Oahu area. Accordingly, HECO transmits bulk power to the Honolulu/East Oahu area over two major transmission corridors (Northern and Southern). HECO had planned to construct a part underground/part overhead 138 kilovolt (kV) transmission line from the Kamoku substation to the Pukele substation in order to close the gap between the Southern and Northern corridors and provide a third 138 kV transmission line to the Pukele substation. Construction of the proposed transmission line in its originally proposed location required the BLNR to approve a CDUP for the overhead portion of the line that would have been in conservation district lands. Several community and environmental groups opposed the project, particularly the overhead portion of the line and, in June 2002, the BLNR denied HECO’s request for a CDUP.

HECO continues to believe that the proposed project (the East Oahu Transmission Project) is needed to improve the reliability of the Pukele substation, which serves approximately 16% of Oahu’s electrical load, including Waikiki, and to address future potential line overloads under certain contingencies. In 2003, HECO completed its evaluation of alternative ways to accomplish the project (including using 46 kV transmission lines). As part of its evaluation, HECO conducted a community-based process to obtain public views of the alternatives. In December 2003, HECO filed an application with the PUC requesting approval to commit funds (currently estimated at $55 million) for its revised East Oahu Transmission Project. Six groups and two individuals have sought to intervene in the preceeding.

Subject to PUC approval, the revised project, none of which is in conservation district lands, will be built in two phases. Completion of the first phase, targeted for 2006, will address future potential transmission line overloads in the Northern and Southern corridors and improve the reliability of service to many customers in the Pukele substation service area, including Waikiki. The second phase, projected to take an additional two years to complete, will improve service to additional customers in the Pukele substation service area by minimizing the duration of service interruptions that could occur under certain contingencies.

As of December 31, 2003, the accumulated costs related to the East Oahu Transmission Project amounted to $20 million, including $13 million for planning, engineering and permitting costs and $7 million for AFUDC. These costs are recorded in construction in progress. The recovery of costs relating to the project is subject to the rate-making process administered by the PUC. Management believes no adjustment to project costs incurred is required as of December 31, 2003. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HECO may be required to write off a material portion or all of the project costs incurred in its efforts to put the project into service whether or not it is completed.

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

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

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

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

25

treble damages, attorneys’ fees, rescission of the amended PPA and punitive damages against HECO, HEI, AES Hawaii and AES.

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

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

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

On August 25, 2003, the First Circuit Court issued an order dismissing with prejudice the amended complaint, including all of the Plaintiffs’ remaining claims against the defendants for violations under the Hawaii False Claims Act after May 26, 2000. The final judgment was entered on September 17, 2003. On October 15, 2003, plaintiff Beverly J. Perry filed a notice of appeal to the Hawaii Supreme Court and the Intermediate Court of Appeals, on the grounds that the Circuit Court erred in its reliance on the doctrine of primary jurisdiction and the statute of limitations. AES subsequently filed a cross-appeal of the order denying its motion to dismiss the action, which it had filed on February 24, 2003. Plaintiff Perry filed her opening brief on February 9, 2004 and HEI/HECO’s answering brief is due on March 19, 2004.

Environmental regulation

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

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

Under the terms of the 1999 agreement for the sale of assets of HTB and the stock of YB, HEI and The Old Oahu Tug Service, Inc. (TOOTS, formerly HTB) have specified indemnity obligations, including obligations with

26

respect to the Honolulu Harbor investigation. In April 2003, TOOTS agreed to pay $250,000 (for TOOTS and HEI) to the Participating Parties to fund response activities in the Iwilei Unit of the Honolulu Harbor site, as a one-time cash-out payment in lieu of continuing with further response activities.

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

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

Management developed a preliminary estimate of HECO’s share of costs primarily from 2002 through 2004 for continuing investigative work, remedial activities and monitoring at the Iwilei Unit of approximately $1.1 million (of which $0.25 million has been incurred through December 31, 2003). The $1.1 million estimate was expensed in 2001. Also, individual companies have incurred costs to remediate their facilities which will not be allocated to the Participating Parties. Because (1) the full scope and extent of additional investigative work, remedial activities and monitoring are unknown at this time, (2) the final cost allocation method has not yet been determined and (3) management cannot estimate the costs to be incurred (if any) for the sites other than the Iwilei Unit (including its Honolulu power plant site), the cost estimate may be subject to significant change and additional material investigative and remedial costs may be incurred.

Maalaea Units 12 and 13 notice and finding of violation. On September 5, 2003, MECO received a Notice of Violation (NOV) issued by the Department of Health of the State of Hawaii (DOH) alleging violations of opacity conditions in permits issued under the DOH’s Air Pollution Control Law for two generating units at MECO’s Maalaea Power Plant. The NOV ordered MECO to immediately take corrective action to prevent further opacity incidents. The NOV also ordered MECO to pay a penalty of $1.6 million, unless MECO submitted a written request for a hearing. In September 2003, MECO submitted a request for hearing and accrued $1.6 million for the potential penalty. An environmental penalty or a settlement of an environmental penalty is not tax deductible.

On December 23, 2003, the DOH and MECO reached a conditional settlement of the NOV, which is subject to public notice and a comment period of at least 30 days. The settlement consists of a Proposed Consent Order that requires MECO to come into full compliance with the opacity rules for the units by December 31, 2004 and to pay a penalty of approximately $0.8 million to the DOH. If signed, the Proposed Consent Order would resolve all civil liability of MECO to the DOH for all opacity violations from February 1, 1999 to December 31, 2004. The DOH has agreed that it will sign the Proposed Consent Order after the close of the public comment period if it continues to conclude that the settlement is appropriate. The public comment period expires in late February 2004. MECO has made significant progress in reducing the number of opacity exceedances from Maalaea Units 12 and 13 and expects to achieve full compliance with the opacity regulations during the Proposed Consent Order period without having to incur significant additional costs.

Since the settlement is subject to public notice and comment and final action by the DOH, management can provide no assurance that the Consent Order will be approved and executed by the DOH in the form proposed. However, management believes at this time that $0.8 million is the probable penalty amount for the NOV. Accordingly, MECO reduced the initial September 2003 accrual of $1.6 million to $0.8 million in December 2003.

27

Collective bargaining agreements.

On November 7, 2003, members of the International Brotherhood of Electrical Workers (IBEW), AFL-CIO, Local 1260, Unit 8, ratified new collective bargaining and benefit agreements with HECO, HELCO and MECO. Of the three companies’ approximately 1,860 employees, about 1,100 are members of IBEW, AFL-CIO, Local 1260, Unit 8, which is the only union representing employees of the Company. The new collective bargaining and benefit agreements cover a four-year term, from November 1, 2003 to October 31, 2007, and provide for non-compounded wage increases (3% on November 1, 2003, 1.5% on November 1, 2004, 1.5% on May 1, 2005, 1.5% on November 1, 2005, 1.5% on May 1, 2006, and 3% on November 1, 2006) and include changes to medical, drug, vision and dental plans and increased employee contributions.

12. Regulatory restrictions on distributions to parent

At December 31, 2003, net assets (assets less liabilities and preferred stock) of approximately $449 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 $2.9 million, $2.2 million and $2.0 million for general management and administrative services in 2003, 2002 and 2001, 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 nil, $2.1 million and $2.2 million for data processing services in 2003, 2002 and 2001, respectively.

HECO’s borrowings from HEI fluctuate during the year, and totaled $6.0 million and $5.6 million at December 31, 2003 and 2002, 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 $0.1 million, $0.4 million and $1.2 million in 2003, 2002 and 2001, 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.

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.

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The estimated fair values of the financial instruments held or issued by the Company were as follows:

December 31	2003				2002
(in thousands)	Carrying Amount		Estimated fair value		Carrying amount		Estimated fair value
Financial assets:
Cash and equivalents	$	158	$	158	$	1,726	$	1,726
Financial liabilities:
Short-term borrowings from affiliate		6,000		6,000		5,600		5,600
Long-term debt, net, including amounts due within one year		699,420		725,329		705,270		735,694
HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO and HECO-guaranteed debentures		100,000		100,920		100,000		100,120

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.

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16. Consolidating financial information (unaudited)

Consolidating balance sheet

	December 31, 2003
(in thousands)	HECO			HELCO		MECO		Renewable Hawaii, Inc.	HECO Capital Trust I	HECO Capital Trust II	Reclassifications and Eliminations		HECO Consolidated
Assets
Utility plant, at cost
Land	$	23,010		3,017		3,600		—	—	—	—		$	29,627
Plant and equipment		2,086,383		589,360		630,385		—	—	—	—			3,306,128
Less accumulated depreciation		(814,699	)	(238,320	)	(237,910	)	—	—	—	—			(1,290,929	)
Plant acquisition adjustment, net		—		—		249		—	—	—	—			249
Construction in progress		93,450		95,879		5,966		—	—	—	—			195,295
Net utility plant		1,388,144		449,936		402,290		—	—	—	—			2,240,370
Investment in wholly owned subsidiaries, at equity		364,973		—		—		—	—	—	(364,973	)[2]		—
Current assets
Cash and equivalents		9		4		87		58	—	—	—			158
Advances to affiliates		10,800		—		25,500		—	51,546	51,546	(139,392	)[1]		—
Customer accounts receivable, net		63,227		16,077		12,695		—	—	—	—			91,999
Accrued unbilled revenues, net		41,200		10,697		8,475		—	—	—	—			60,372
Other accounts receivable, net		2,030		754		443		—	—	—	(894	)[1]		2,333
Fuel oil stock, at average cost		32,060		3,526		8,026		—	—	—	—			43,612
Materials & supplies, at average cost		10,331		2,536		8,366		—	—	—	—			21,233
Prepayments and other		69,051		11,621		6,091		—	—	—	—			86,763
Total current assets		228,708		45,215		69,683		58	51,546	51,546	(140,286	)		306,470
Other assets
Unamortized debt expense		9,492		2,328		2,215		—	—	—	—			14,035
Long-term receivables and other		14,658		3,366		2,357		—	—	—	—			20,381
Total other assets		24,150		5,694		4,572		—	—	—	—			34,416
	$	2,005,975		500,845		476,545		58	51,546	51,546	(505,259	)	$	2,581,256
Capitalization and liabilities
Capitalization
Common stock equity	$	944,443		174,639		187,195		47	1,546	1,546	(364,973	)[2]	$	944,443
Cumulative preferred stock–not subject to mandatory redemption		22,293		7,000		5,000		—	—	—	—			34,293
HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO & HECO-guaranteed debentures		—		—		—		—	50,000	50,000	—			100,000
Long-term debt, net		497,915		140,868		163,729		—	—	—	(103,092	)[1]		699,420
Total capitalization		1,464,651		322,507		355,924		47	51,546	51,546	(468,065	)		1,778,156
Current liabilities
Short-term borrowings-affiliate		31,500		10,800		—		—	—	—	(36,300	)[1]		6,000
Accounts payable		49,423		10,593		12,361		—	—	—	—			72,377
Interest and preferred dividends payable		7,890		1,387		2,057		—	—	—	(31	)[1]		11,303
Taxes accrued		58,562		16,523		18,218		—	—	—	—			93,303
Other		20,752		7,772		6,343		11	—	—	(863	)[1]		34,015
Total current liabilities		168,127		47,075		38,979		11	—	—	(37,194	)		216,998
Deferred credits and other liabilities
Deferred income taxes		137,919		20,079		12,843		—	—	—	—			170,841
Regulatory liabilities		42,235		18,935		10,712		—	—	—	—			71,882
Unamortized tax credits		27,703		8,633		10,730		—	—	—	—			47,066
Other		21,525		27,341		13,478		—	—	—	—			62,344
Total deferred credits and other liabilities		229,382		74,988		47,763		—	—	—	—			352,133
Contributions in aid of construction		143,815		56,275		33,879		—	—	—	—			233,969
	$	2,005,975		500,845		476,545		58	51,546	51,546	(505,259	)	$	2,581,256

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Consolidating balance sheet

	December 31, 2002
(in thousands)	HECO			HELCO		MECO		HECO Capital Trust I	HECO Capital Trust II	Reclassifications and Eliminations		HECO Consolidated
Assets
Utility plant, at cost
Land	$	22,836		2,982		3,585		—	—	—		$	29,403
Plant and equipment		2,025,480		565,920		595,911		—	—	—			3,187,311
Less accumulated depreciation		(765,578	)	(222,360	)	(217,398	)	—	—	—			(1,205,336	)
Plant acquisition adjustment, net		—		—		302		—	—	—			302
Construction in progress		63,246		93,428		7,626		—	—	—			164,300
Net utility plant		1,345,984		439,970		390,026		—	—	—			2,175,980
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
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		24,492		5,321		5,784		—	—	—			35,597
	$	1,942,377		485,537		460,533		51,546	51,546	(498,103	)	$	2,493,436
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
Regulatory liabilities		31,808		16,556		8,686		—	—	—			57,050
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		215,838		66,315		46,093		—	—	—			328,246
Contributions in aid of construction		138,298		54,288		25,508		—	—	—			218,094
	$	1,942,377		485,537		460,533		51,546	51,546	(498,103	)	$	2,493,436

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Consolidating statement of income

	Year ended December 31, 2003
(in thousands)	HECO			HELCO		MECO		Renewable Hawaii, Inc.		HECO Capital Trust I	HECO Capital Trust II	Reclassifications and Eliminations		HECO Consolidated
Operating revenues	$	963,500		214,243		215,295		—		—	—	—		$	1,393,038
Operating expenses
Fuel oil		273,905		31,853		82,802		—		—	—	—			388,560
Purchased power		284,549		75,042		8,485		—		—	—	—			368,076
Other operation		102,441		25,643		27,447		—		—	—	—			155,531
Maintenance		38,505		13,737		12,379		—		—	—	—			64,621
Depreciation		67,121		20,293		23,146		—		—	—	—			110,560
Taxes, other than income taxes		90,150		20,105		20,422		—		—	—	—			130,677
Income taxes		31,113		7,120		11,942		—		—	—	—			50,175
		887,784		193,793		186,623		—		—	—	—			1,268,200
Operating income		75,716		20,450		28,672		—		—	—	—			124,838
Other income
Allowance for equity funds used during construction		3,652		170		445		—		—	—	—			4,267
Equity in earnings of subsidiaries		29,459		—		—		—		—	—	(29,459	)[2]		—
Other, net		2,667		315		(557	)	(133	)	4,149	3,763	(8,301	)[1]		1,903
		35,778		485		(112	)	(133	)	4,149	3,763	(37,760	)		6,170
Income before interest and other charges		111,494		20,935		28,560		(133	)	4,149	3,763	(37,760	)		131,008
Interest and other charges
Interest on long-term debt		25,284		7,016		8,398		—		—	—	—			40,698
Amortization of net bond premium and expense		1,371		364		396		—		—	—	—			2,131
Preferred securities distributions of trust subsidiaries		—		—		—		—		—	—	7,675	[3]		7,675
Other interest charges		6,506		1,952		1,354			1	—	—	(8,301	)[1]		1,512
Allowance for borrowed funds used during construction		(1,658	)	(80	)	(176	)	—		—	—	—			(1,914	)
Preferred stock dividends of subsidiaries		—		—		—		—		—	—	915	[3]		915
		31,503		9,252		9,972			1	—	—	289			51,017
Income before preferred stock dividends of HECO		79,991		11,683		18,588		(134	)	4,149	3,763	(38,049	)		79,991
Preferred stock dividends of HECO		1,080		534		381		—		4,025	3,650	(8,590	)[3]		1,080
Net income for common stock	$	78,911		11,149		18,207		(134	)	124	113	(29,459	)	$	78,911

Consolidating statement of retained earnings

	Year ended December 31, 2003
(in thousands)	HECO			HELCO		MECO		Renewable Hawaii, Inc.		HECO Capital Trust I		HECO Capital Trust II		Reclassifications and Eliminations		HECO Consolidated
Retained earnings, beginning of period	$	542,023		71,414		87,092		—		—		—		(158,506	)[2]	$	542,023
Net income for common stock		78,911		11,149		18,207		(134	)	124		113		(29,459	)[2]		78,911
Common stock dividends		(57,719	)	(7,934	)	(12,390	)	—		(124	)	(113	)	20,561	[2]		(57,719	)
Retained earnings, end of period	$	563,215		74,629		92,909		(134	)	—		—		(167,404	)	$	563,215

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Consolidating statement of income

	Year ended December 31, 2002
(in thousands)	HECO			HELCO		MECO		HECO Capital Trust I	HECO Capital Trust II	Reclassifications and Eliminations		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
Preferred securities distributions of trust subsidiaries		—		—		—		—	—	7,675	[3]		7,675
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
		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		Reclassifications and Eliminations		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

33

Consolidating statement of income

	Year ended December 31, 2001
(in thousands)	HECO			HELCO		MECO		HECO Capital Trust I	HECO Capital Trust II	Reclassifications and Eliminations		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
Preferred securities distributions of trust subsidiaries		—		—		—		—	—	7,675	[3]		7,675
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
		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		Reclassifications and Eliminations		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

34

Consolidating statement of cash flows

	Year ended December 31, 2003
(in thousands)	HECO			HELCO		MECO		Renewable Hawaii, Inc.		HECO Capital Trust I		HECO Capital Trust II		Elimination addition to (deduction from) cash flows		HECO Consolidated
Cash flows from operating activities:
Income before preferred stock dividends of HECO	$	79,991		11,683		18,588		(134	)	4,149		3,763		(38,049	)[2]	$	79,991
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Equity in earnings		(29,459	)	—		—		—		—		—		29,459	[2]		—
Common stock dividends received from subsidiaries		20,561		—		—		—		—		—		(20,561	)[2]		—
Depreciation of property, plant and equipment		67,121		20,293		23,146		—		—		—		—			110,560
Other amortization		3,973		772		3,487		—		—		—		—			8,232
Deferred income taxes		5,804		5,599		1,116		—		—		—		—			12,519
Tax credits, net		292		388		(95	)	—		—		—		—			585
Allowance for equity funds used during construction		(3,652	)	(170	)	(445	)	—		—		—		—			(4,267	)
Changes in assets and liabilities:
Increase in accounts receivable		(1,291	)	(2,441	)	(926	)	—		—		—		(348	)[1]		(5,006	)
Decrease (increase) in accrued unbilled revenues		72		4		(350	)	—		—		—		—			(274	)
Increase in fuel oil stock		(6,359	)	(80	)	(1,524	)	—		—		—		—			(7,963	)
Increase in materials and supplies		(1,255	)	(288	)	(240	)	—		—		—		—			(1,783	)
Increase in regulatory assets		(1,550	)	(209	)	(3,138	)	—		—		—		—			(4,897	)
Increase in accounts payable		7,829		131		4,425		—		—		—		—			12,385
Increase in taxes accrued		10,288		1,625		2,257		—		—		—		—			14,170
Changes in other assets and liabilities		(14,835	)	(909	)	(486	)	11		—		—		8,023	[2]		(8,196	)
Net cash provided by (used in) operating activities		137,530		36,398		45,815		(123	)	4,149		3,763		(21,476	)		206,056
Cash flows from investing activities:
Capital expenditures		(91,232	)	(29,426	)	(26,306	)	—		—		—		—			(146,964	)
Contributions in aid of construction		6,185		4,629		2,149		—		—		—		—			12,963
Advances from (to) affiliates		4,100		—		(2,500	)	—		—		—		(1,600	)[1]		—
Investment in subsidiary		(181	)	—		—		—		—		—		181	[2]		—
Proceeds from sales of assets		118		—		—		—		—		—		—			118
Net cash used in investing activities		(81,010	)	(24,797	)	(26,657	)	—		—		—		(1,419	)		(133,883	)
Cash flows from financing activities:
Common stock dividends		(57,719	)	(7,934	)	(12,390	)	—		(124	)	(113	)	20,561	[2]		(57,719	)
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 common stock		—		—		—		181		—		—		(181	)[2]		—
Proceeds from issuance of long-term debt		42,098		25,837		—		—		—		—		—			67,935
Repayment of long-term debt		(40,000	)	(26,000	)	(8,000	)	—		—		—		—			(74,000	)
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		2,900		(4,100	)	—		—		—		—		1,600	[1]		400
Other		(2,719	)	1,130		(13	)	—		—		—		—			(1,602	)
Net cash provided by (used in) financing activities		(56,520	)	(11,601	)	(20,784	)	181		(4,149	)	(3,763	)	22,895			(73,741	)
Net increase (decrease) in cash and equivalents		—		—		(1,626	)	58		—		—		—			(1,568	)
Cash and equivalents, beginning of year		9		4		1,713		—		—		—		—			1,726
Cash and equivalents, end of year	$	9		4		87		58		—		—		—		$	158

35

Consolidating statement of cash flows

	Year ended December 31, 2002
(in thousands)	HECO			HELCO		MECO		HECO Capital Trust I		HECO Capital Trust II		Elimination addition to (deduction from) cash flows		HECO Consolidated
Cash flows from operating activities:
Income before preferred stock dividends of HECO	$	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]		—
Proceeds from sales of assets		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 year		9		1,282		567		—		—		—			1,858
Cash and equivalents, end of year	$	9		4		1,713		—		—		—		$	1,726

36

Consolidating statement of cash flows

	Year ended December 31, 2001
(in thousands)	HECO			HELCO		MECO		HECO Capital Trust I		HECO Capital Trust II		Elimination addition to (deduction from) cash flows		HECO Consolidated
Cash flows from operating activities:
Income before preferred stock dividends of HECO	$	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 year		1,398		4		132		—		—		—			1,534
Cash and equivalents, end of year	$	9		1,282		567		—		—		—		$	1,858

37

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 trust preferred securities issued by HECO Capital Trust I and HECO Capital Trust II, which trusts hold the 1997 and 1998 junior deferrable debentures issued by HELCO and MECO, 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 2003 and 2002 follows:

	Quarters ended								Year ended Dec. 31
2003	March 31		June 30		Sept. 30		Dec. 31
(in thousands)
Operating revenues	$	327,961	$	353,385	$	358,435	$	353,257	$	1,393,038
Operating income		29,055		30,041		33,576		32,166		124,838
Net income for common stock		17,656		18,556		20,360		22,339		78,911

	Quarters ended								Year ended Dec. 31
2002	March 31		June 30		Sept. 30		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

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

38

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, 2003 and 2002, and the related consolidated statements of income, retained earnings and cash flows for each of the years in the three-year period ended December 31, 2003. These consolidated financial statements 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, 2003 and 2002, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

/s/ KPMG LLP

Honolulu, Hawaii

February 11, 2004

39