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 25, 2003

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 93813

(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 13.1	HEI’s 2002 Annual Report to Stockholders
HEI Exhibit 99.1	Written Statement Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002 of Robert F. Clarke (HEI Chief Executive Officer)
HEI Exhibit 99.2	Written Statement Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002 of Eric K. Yeaman (HEI Chief Financial Officer)
HECO Exhibit 13.2	Pages 1 to 2, 4 to 57 and 59 of HECO’s 2002 Annual Report to Stockholder
HECO Exhibit 99.3	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 99.4	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)

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. (Registrant)	HAWAIIAN ELECTRIC COMPANY, INC. (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) Date: February 26, 2003	Richard A. von Gnechten Financial Vice President (Principal Financial Officer of HECO) Date: February 26, 2003

EX-13.1

HEI Exhibit 13.1

Hawaiian Electric Industries, Inc.

2002 Annual Report to Stockholders

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

1

Forward-Looking Statements

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

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

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

• the effects of weather and natural disasters;

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

• the timing and extent of changes in interest rates;

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

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

• product demand and market acceptance risks;

• increasing competition in the electric utility and banking industries;

• capacity and supply constraints or difficulties;

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

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

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

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

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

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

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

• the effects of changes by securities rating agencies in the ratings of the securities of HEI and Hawaiian Electric Company, Inc. (HECO);

• the results of financing efforts;

• faster than expected loan prepayments that can cause an acceleration of the amortization of premiums on loans and investments and the impairment of ASB’s mortgage servicing rights;

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

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

• the risks of suffering losses that are uninsured; and

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

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

2

Selected Financial Data

Hawaiian Electric Industries, Inc. and Subsidiaries

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

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

** At December 31.

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

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

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

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

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

Strategy

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

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

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

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

Results of operations

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

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

4

Economic conditions

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

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

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

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

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

Consolidated

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

5

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

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

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

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

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

Electric utility

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

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

Ÿ In 2002, the electric utilities’ revenues decreased by 2%, or $32 million, from 2001 primarily due to lower energy prices ($60 million), partly offset by a 1.9% increase in KWH sales of electricity ($25 million). The increase in 2002 KWH sales from 2001 was primarily due to increases in residential usage and the number of residential customers and a recovery in the local economy following the events of the September 11, 2001 terrorist attacks, in spite of cooler temperatures which typically result in lower residential and commercial air conditioning usage. Operating income for 2002 was slightly higher than 2001. Fuel oil expense decreased 10% due primarily to lower fuel oil prices, partly offset by more KWHs generated. Purchased power expense decreased 3% due primarily to lower fuel prices and lower purchased capacity payments to an independent power producer (IPP) who was able to produce only an average of about 5.6 megawatts (MW) of firm capacity since April 2002 compared to the 30 MW the IPP contracted to provide to Hawaii Electric Light Company, Inc. (HELCO). Other expenses were up 4% due to a 5% increase in other operation expense (including $7 million lower retirement benefits income, net of amounts capitalized, primarily due to a 25 basis points lower discount rate and the market performance of plan assets – i.e., $10 million retirement benefits income in 2002 compared to $17 million in 2001), an 8% increase in maintenance expense partly due to the timing and larger scope of generating unit overhauls, a 5% increase in depreciation expense, partly offset by a 1% decrease in taxes, other than income taxes. The allowance for funds used during construction (AFUDC) for 2002 was 11% lower than 2001 due to the lower base on which AFUDC was calculated. Interest expense decreased 6% from 2001 due to lower short-term borrowings and interest rates.

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

6

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

Recent rate requests

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

Hawaiian Electric Company, Inc. HECO has not initiated a rate case for several years, but in 2001 it committed to initiate a rate case within three years, using a 2003 or 2004 test year, as part of the agreement described below under “Other regulatory matters, Demand-side management programs – agreements with the Consumer Advocate.” In October 2002, HECO filed an application with the PUC for approval to change its depreciation rates and to change to vintage amortization accounting for selected plant accounts, which changes would have amounted to an estimated $4.2 million, or 6.3%, increase in depreciation expense based on a study of depreciation expense for 2000. In its application, HECO requested that the effective date of the proposed changes coincide with the effective date of the rates established in HECO’s next rate case proceeding so that HECO’s financial results would not be negatively impacted by the depreciation rates and method ultimately approved by the PUC.

Hawaii Electric Light Company, Inc. In early 2001, HELCO received a final D&O from the PUC authorizing an $8.4 million, or 4.9% increase in annual revenues, effective February 15, 2001 and based on an 11.50% ROACE. The D&O included in rate base $7.6 million for pre-air permit facilities needed for the delayed Keahole power plant expansion project that the PUC had also found to be used or useful to support the existing generating units at Keahole. The timing of a future HELCO rate increase request to recover costs relating to the delayed Keahole power plant expansion project, i.e., adding two combustion turbines (CT-4 and CT-5) at Keahole, including the remaining cost of pre-air permit facilities, will depend on future circumstances. See “Certain factors that may affect future results and financial condition–Electric utility–Other regulatory and permitting contingencies” and “HELCO power situation” in Note 3 of the “Notes to Consolidated Financial Statements.”

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

Other regulatory matters

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

Lost margins are accrued and collected prospectively based on the programs’ forecasted levels of participation, and are subject to two adjustments based on (1) the actual level of participation and (2) the results of impact

7

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

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

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

Collective bargaining agreements

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

Legislation

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

In its 2001 session, the Hawaii legislature passed a law establishing “renewable portfolio standard” goals for electric utilities of 7% by December 31, 2003, 8% by December 31, 2005 and 9% by December 31, 2010. HECO,

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

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

Bank

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

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

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

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

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	Years ended December 31,
	2002			2001			2000
	(in thousands)
Loans
Average balances1	$	2,844,341		$	2,963,521		$	3,215,879
Interest income2		203,082			231,858			254,502
Weighted-average yield		7.14	%		7.82	%		7.91	%
Mortgage-related securities
Average balances	$	2,654,302		$	2,345,630		$	2,058,706
Interest income		135,252			152,181			152,340
Weighted-average yield		5.10	%		6.49	%		7.40	%
Investments3
Average balances	$	246,321		$	308,712		$	287,906
Interest and dividend income		7,896			15,612			16,733
Weighted-average yield		3.21	%		5.06	%		5.81	%
Total interest-earning assets
Average balances	$	5,744,964		$	5,617,863		$	5,562,491
Interest and dividend income		346,230			399,651			423,575
Weighted-average yield		6.03	%		7.11	%		7.61	%
Deposits
Average balances	$	3,717,553		$	3,638,136		$	3,537,312
Interest expense		73,631			116,531			119,192
Weighted-average rate		1.98	%		3.20	%		3.37	%
Borrowings
Average balances	$	1,770,831		$	1,778,766		$	1,880,952
Interest expense		79,251			97,054			119,683
Weighted-average rate		4.48	%		5.46	%		6.36	%
Total interest-bearing liabilities
Average balances	$	5,488,384		$	5,416,902		$	5,418,264
Interest expense		152,882			213,585			238,875
Weighted-average rate		2.79	%		3.94	%		4.41	%
Net balance, net interest income and interest rate spread
Net balance	$	256,580		$	200,961		$	144,227
Net interest income		193,348			186,066			184,700
Interest rate spread		3.24	%		3.17	%		3.20	%

¹ Includes nonaccrual loans.

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

³ Includes stock in the FHLB of Seattle.

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

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

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

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

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

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

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

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

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

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

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

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

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

Regulation

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

Other

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

¹ Including writedowns of and net losses from investments.

NM Not meaningful.

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

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

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

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

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

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

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

Effects of inflation

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

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

Recent accounting pronouncements

See “Recent accounting pronouncements” in Note 1 of the “Notes to Consolidated Financial Statements.”

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Liquidity and capital resources

Consolidated

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

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

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

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

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

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

NR Not rated.

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

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

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

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

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

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

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

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

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

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

15

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

As further explained in Note 8 in the “Notes to Consolidated Financial Statements,” the Company maintains pension and other postretirement benefit plans. Funding for the pension plans is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under the Employee Retirement Income Security Act of 1974, as amended (ERISA). The Company is not required to make any contributions to the pension plans to meet minimum funding requirements pursuant to ERISA for 2003, but the Company’s Pension Investment Committee may choose to make contributions to the pension plans in 2003. The electric utilities’ policy is to comply with directives from the PUC to fund the costs of the postretirement benefit plan. These costs are ultimately collected in rates billed to customers. The Company reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed. Due to the sharp declines in U.S. equity markets beginning in 2000, the value of a significant portion of the assets held in the plans’ trusts to satisfy the obligations of the pension and other postretirement plans has decreased significantly. As a result, additional contributions may be required in the future to meet the minimum funding requirements of ERISA or to pay benefits to plan participants. The Company believes it will have adequate access to capital resources to support any necessary funding requirements.

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

Electric utility

HECO’s consolidated capital structure was as follows:

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

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

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

As of December 31, 2002, $16 million of proceeds from the Series 2002A sale by the Department of Budget and Finance of the State of Hawaii of special purpose revenue bonds issued for the benefit of HECO remain undrawn. Also as of December 31, 2002, an additional $25 million of special purpose revenue bonds were authorized by the Hawaii Legislature for issuance for the benefit of HELCO prior to the end of 2003.

The electric utilities’ consolidated financing requirements for 2003 through 2007, including net capital expenditures and long-term debt repayments, are estimated to total $0.7 billion. HECO’s consolidated internal sources (primarily consolidated cash flows from operations comprised mainly of net income, adjusted for noncash income and expense items such as depreciation, amortization and deferred taxes, and changes in working capital), after the payment of common stock and preferred stock dividends, are expected to provide cash in excess of the consolidated financing requirements and may be used to reduce the level of borrowings. HECO does not anticipate the need to issue common equity over the five-year period 2003 through 2007. Debt and/or equity financing may be required, however, to fund unanticipated expenditures not included in the 2003 through 2007 forecast, such as

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increases in the costs of or an acceleration of the construction of capital projects, unbudgeted acquisitions or investments in new businesses and significant increases in retirement benefit funding requirements that might be required if there were significant declines in the market value of pension plan assets or changes in actuarial assumptions. The PUC must approve issuances, if any, of equity and long-term debt securities by HECO, HELCO and MECO.

Capital expenditures include the costs of projects that are required to meet expected load growth, to improve reliability and to replace and upgrade existing equipment. Net capital expenditures for the five-year period 2003 through 2007 are currently estimated to total $0.7 billion. Approximately 53% of forecasted gross capital expenditures (which includes the allowance for funds used during construction and capital expenditures funded by third-party contributions in aid of construction) is for transmission and distribution projects, with the remaining 47% primarily for generation projects.

For 2003, electric utility net capital expenditures are estimated to be $158 million. Gross capital expenditures are estimated to be $183 million, including approximately $103 million for transmission and distribution projects, approximately $58 million for generation projects and approximately $22 million for general plant and other projects. Drawdowns of the remaining $16 million of proceeds from the Series 2002A sale of tax-exempt special purpose revenue bonds and the generation of funds from internal sources are expected to provide the cash needed for the net capital expenditures in 2003.

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

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

Bank

	December 31
			%				%
	2002		change		2001		change
	(in millions)
Assets	$	6,329	5		$	6,011	1
Available-for-sale mortgage-related securities		2,737	16			2,355	1,330
Held-to-maturity investment securities		90	6			84	(96	)
Loans receivable, net		2,994	5			2,858	(11	)
Deposit liabilities		3,801	3			3,680	3
Securities sold under agreements to repurchase		667	(2	)		683	15
Advances from FHLB		1,176	14			1,033	(17	)

As of December 31, 2002, ASB was the third largest financial institution in Hawaii based on assets of $6.3 billion and deposits of $3.8 billion.

ASB’s principal sources of liquidity are customer deposits, wholesale borrowings, the sale of mortgage loans into secondary market channels and the maturity and repayment of portfolio loans and mortgage-related securities. ASB’s deposits increased by $121 million during 2002. ASB’s principal sources of borrowings are advances from the FHLB and securities sold under agreements to repurchase from broker/dealers. At December 31, 2002, FHLB borrowings totaled $1.2 billion, representing 19% of assets. ASB is approved by the FHLB to borrow up to 35% of assets to the extent it provides qualifying collateral and holds sufficient FHLB stock. At December 31, 2002, ASB’s unused FHLB borrowing capacity was approximately $1.0 billion. At December 31, 2002, securities sold under agreements to repurchase totaled $0.7 billion, representing 11% of assets. ASB utilizes growth in deposits, advances from the FHLB and securities sold under agreements to repurchase to fund maturing and withdrawable deposits, repay maturing borrowings, fund existing and future loans and make investments. At December 31, 2002, ASB had commitments to borrowers for undisbursed loan funds and unused lines and letters of credit of $0.8 billion.

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Management believes ASB’s current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.

In June 2001, ASB converted $0.4 billion in residential mortgage loans into FNMA pass-through securities. These securities were transferred into the investment securities portfolio and can serve as collateral for FHLB advances and other borrowings. The conversion of the loans also improves ASB’s risk-based capital ratio since less capital is needed to support federal agency securities than whole loans. In late June 2001, ASB sold $0.2 billion of the FNMA securities to improve ASB’s interest-rate risk profile. The securities sold were lower yielding 30-year fixed-rate securities with long remaining durations. ASB reinvested the proceeds into shorter duration fixed-rate and adjustable-rate securities.

At December 31, 2002, ASB had $15.8 million of loans on nonaccrual status, or 0.5% of net loans outstanding, compared to $37.6 million, or 1.3%, at December 31, 2001. At December 31, 2002 and 2001, ASB’s real estate acquired in settlement of loans was $12.1 million and $14.5 million, respectively.

In 2002, net cash of $497 million was used in investing activities largely for the purchase of mortgage-related securities and origination and purchase of loans, net of repayments and sales of such securities. Financing activities provided net cash of $213 million due to net increases in deposits and advances from the FHLB, partly offset by the payment of common and preferred stock dividends and a net decrease in securities sold under agreements to repurchase. Operating activities provided cash of $73 million.

ASB believes that a satisfactory regulatory capital position provides a basis for public confidence, affords protection to depositors, helps to ensure continued access to capital markets on favorable terms and provides a foundation for growth. FDIC regulations restrict the ability of financial institutions that are not well-capitalized to compete on the same terms as well-capitalized institutions, such as by offering interest rates on deposits that are significantly higher than the rates offered by competing institutions. As of December 31, 2002, ASB was well-capitalized (ratio requirements noted in parentheses) with a leverage ratio of 6.7% (5.0%), a Tier-1 risk-based capital ratio of 13.5% (6.0%) and a total risk-based capital ratio of 14.7% (10.0%).

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Selected contractual obligations and commitments

The following tables present aggregated information about certain contractual obligations and commercial commitments:

	December 31, 2002
	Payment due by period
	Less than 1 year		1-3 years		4-5 years		After 5 years		Total
	(in millions)
Contractual obligations
Deposit liabilities
Commercial checking	$	242	$	—	$	—	$	—	$	242
Other checking		621		—		—		—		621
Passbook		1,226		—		—		—		1,226
Money market		443		—		—		—		443
Term certificates		506		593		119		51		1,269
Total deposit liabilities	$	3,038	$	593	$	119	$	51	$	3,801
Securities sold under agreements to repurchase		305		362		—		—		667
Advances from Federal Home Loan Bank		273		711		192		—		1,176
Long-term debt		136		38		120		812		1,106
HEI and HECO—obligated preferred securities of trust subsidiaries		—		—		—		200		200
Operating leases, service bureau contract and maintenance agreements		19		26		9		20		74
Fuel oil purchase obligations (estimate based on January 1, 2003 fuel oil prices)		329		330		—		—		659
Purchase power obligations—minimum fixed capacity charges		123		241		236		1,607		2,207
	$	4,223	$	2,301	$	676	$	2,690	$	9,890

	December 31, 2002
	(in millions)
Other commercial commitments
Loan commitments and loans in process (primarily expiring in 2003)	$	91
Unused lines and letters of credit		701
	$	792

The tables above do not include other categories of obligations and commitments, such as trade payables, obligations under purchase orders, amounts that may become payable in future periods under collective bargaining and other employment agreements and employee benefit plans, and obligations that may arise under indemnities provided to purchasers of discontinued operations.

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Certain factors that may affect future results and financial condition

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

Consolidated

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

Competition. The electric utility and banking industries are competitive and the Company’s success in meeting competition will continue to have a direct impact on the Company’s financial performance.

Electric utility. The electric utility industry in Hawaii has become increasingly competitive. IPPs are well established in Hawaii and continue to actively pursue new projects. Competition in the generation sector in Hawaii is moderated, however, by the scarcity of generation sites, various permitting processes and lack of interconnections to other electric utilities. Customer self-generation, with or without cogeneration, is a continuing competitive factor. Historically, HECO and its subsidiaries have been able to compete by offering customers economic alternatives that, among other things, employ energy efficient electrotechnologies such as the heat pump water heater. However, the number of customer self-generation projects that are being proposed or installed in Hawaii, particularly those involving combined heat and power (CHP) systems, is growing. CHP systems are a form of distributed generation (DG), and produce electricity and thermal energy from gas, propane or diesel-fired engines. In Hawaii, the thermal energy generally is used to heat water and, through an absorption chiller, drive an air conditioning system. The electric energy generated by these systems is usually lower in output than the customer’s load, which results in continued connection to the utility grid to make up the difference in electricity demand and to provide back up electricity.

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

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

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

In December 1999, HECO, HELCO and MECO filed an application with the PUC seeking permission to implement PBR in future rate cases. In early 2001, the PUC dismissed the PBR proposal without prejudice, indicating

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it declined at that time to change its current cost of service/rate of return methodology for determining electric utility rates.

In January 2000, the PUC submitted to the legislature a status report on its investigation of competition. The report stated that competitive bidding for new power supplies (i.e., wholesale generation competition) is a logical first step to encourage competition in Hawaii’s electric industry and that the PUC plans to proceed with an examination of the feasibility of competitive bidding and to review specific policies to encourage renewable energy resources in the power generation mix. The report states that “further steps” by the PUC “will involve the development of specific policies to encourage wholesale competition and the continuing examination of other areas suitable for the development of competition.” HECO is unable to predict the ultimate outcome of the proceeding, which of the proposals (if any) advanced in the proceeding will be implemented or whether the parties will seek and obtain state legislative action on their proposals (other than the legislation described above under “Results of operations–Electric utility–Legislation”).

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

The primary factors in competing for deposits are interest rates, the quality and range of services offered, marketing, convenience of locations, hours of operation and perceptions of the institution’s financial soundness and safety. To meet competition, ASB offers a variety of savings and checking accounts at competitive rates, convenient business hours, convenient branch locations with interbranch deposit and withdrawal privileges at each branch and convenient automated teller machines. ASB also conducts advertising and promotional campaigns.

The primary factors in competing for first mortgage and other loans are interest rates, loan origination fees and the quality and range of lending and other services offered. ASB believes that it is able to compete for such loans primarily through the competitive interest rates and loan fees it charges, the type of mortgage loan programs it offers and the efficiency and quality of the services it provides to individual borrowers and the business community.

ASB is expanding its traditional consumer focus to be a full-service community bank and is diversifying its loan portfolio from single-family home mortgages to higher-yielding business and commercial real estate loans. The origination of consumer, business banking and commercial real estate loans involves risks different from those associated with originating residential real estate loans. For example, the sources and level of competition may be different and credit risk is generally higher than for mortgage loans. These different risk factors are considered in the underwriting and pricing standards established by ASB for its consumer, business banking and commercial real estate loans.

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

U.S. capital markets and interest rate environment. Changes in the U.S. capital markets can have significant effects on the Company. For example:

• The Company estimates that retirement benefits expense, net of amounts capitalized and income taxes, will be $12 million in 2003 as compared to net retirement benefits income of $4 million in 2002 (or $16 million less net income), partly as a result of the effect of the stock market decline on the performance of the assets in HEI’s master pension trust.

• Volatility in U.S. capital markets or higher delinquencies in the assets underlying the mortgage-related securities held by ASB and the income notes acquired by HEI in connection with ASB’s disposition of certain trust certificates may negatively impact their fair values in future periods. As of December 31, 2002, the fair value and carrying value of the mortgage-related securities held by ASB and the income notes held by HEI were $2.7 billion and $8.0 million, respectively.

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Interest rate risk is a significant risk of ASB’s operations. ASB actively manages this risk, including managing the relationship of its interest-sensitive assets to its interest-sensitive liabilities. See “Quantitative and Qualitative Disclosures about Market Risk.” HEI and HECO and its subsidiaries are exposed to interest rate risk primarily due to their borrowings. They attempt to manage this risk in part by incurring or refinancing debt in periods of low interest rates and by usually issuing fixed-rate rather than floating-rate long-term debt. As of December 31, 2002, the Company had no commercial paper outstanding and $100 million of floating-rate medium-term notes outstanding.

Federal government monetary policies and low interest rates have resulted in increased mortgage refinancing volume as well as accelerated prepayments of loans and securities. ASB’s interest rate spread, the difference between the yield on interest-earning assets and the cost of funds, was compressed in the fourth quarter of 2002 and may continue to be compressed if yields on assets decline more rapidly than the cost of funds.

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

Discontinued operations and asset dispositions. The Company has discontinued or sold its international power, maritime freight transportation and real estate operations in recent years. See Note 13 in the “Notes to Consolidated Financial Statements.” Problems may be encountered or liabilities may arise in the exit from these operations. For example, in accounting for the discontinuance of operations under accounting standards at the time of discontinuation, estimates were made by management concerning the amounts that would be realized upon the sale of those operations (including income tax benefits to be realized) and concerning the costs and liabilities that would be incurred in connection with the discontinuation. Management made these estimates based on the information available, but the amounts finally realized on disposition of the discontinued operations, and the amount of the liabilities and costs ultimately incurred in connection with those operations, may differ materially from the recorded amounts due to many factors, including changes in current economic and political conditions, both domestically and internationally. Management continues to monitor significant changes in economic and political conditions and the impact these developments may have on the Company’s net assets of discontinued operations. At December 31, 2002, the net assets of the discontinued international power and real estate operations amounted to $17 million.

In addition, in connection with prior dispositions of operations, additional unrecorded liabilities may arise if claims are asserted under indemnities provided in connection with the dispositions. For example, TOOTS is participating in the Honolulu Harbor environmental investigation on behalf of its former maritime freight transportation operations under an indemnity arrangement entered into in connection with the sale of those operations. See Note 3 in the “Notes to Consolidated Financial Statements.”

It is also possible that the Company may recover amounts relating to claims arising in connection with discontinued operations or the disposition of assets that have been written down. For example, HEIPC and its subsidiaries are pursuing recovery of the $25 million of costs incurred in connection with a joint venture interest in a China project that was previously expensed or written off when the Company decided to exit the international power business. Also, ASB is pursuing claims against a broker to recover losses incurred in connection with certain trust certificates acquired from the broker and subsequently disposed of by ASB. See Note 4 in the “Notes to Consolidated Financial Statements.” Pursuit of such recoveries may be costly and there can be no assurance that the pursuit of any of these claims will be successful or that any amounts will be recovered.

Limited insurance. In the ordinary course of business, the Company purchases insurance coverages (e.g., property and liability coverages) to protect itself against loss of or damage to its properties and against claims made by third-parties and employees for property damage or personal injuries. However, the protection provided by such insurance is limited in significant respects and, in some instances, the Company has no coverage. For example the electric utilities’ overhead and underground transmission and distribution systems (with the exception of substation buildings and contents) have a replacement value roughly estimated at $2 billion and are uninsured because the amount of transmission and distribution system insurance available is limited and the premiums are cost prohibitive. Similarly, the electric utilities have no business interruption insurance as the premiums for such insurance would be cost prohibitive, particularly since the utilities are not interconnected to other systems. If a hurricane or other

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uninsured catastrophic natural disaster should occur, and the PUC does not allow the Company to recover from ratepayers restoration costs and revenues lost from business interruption, the Company’s results of operations and financial condition could be materially adversely impacted. Also, certain of the Company’s insurance has substantial “deductibles” or has limits on the maximum amounts that may be recovered. Insurers have also introduced new exclusions or limitations of coverage for claims related to certain perils including, but not limited to, mold and terrorism. If a series of losses occurred, such as from a series of lawsuits in the ordinary course of business each of which were subject to the deductible amount, or if the maximum limit of the available insurance were substantially exceeded, the Company could incur losses in amounts that would have a material adverse effect on its results of operations and financial condition.

Environmental matters. HEI and its subsidiaries are subject to environmental laws and regulations that regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic substances. These laws and regulations, among other things, require that certain environmental permits be obtained as a condition to constructing or operating certain facilities, and obtaining such permits can entail significant expense and cause substantial construction delays. Also, these laws and regulations may be amended from time to time, including amendments that increase the burden and expense of compliance. Management believes that the recovery through rates of most, if not all, of any costs incurred by HECO and its subsidiaries in complying with environmental requirements would be allowed by the PUC.

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

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

An ongoing environmental investigation is the Honolulu Harbor environmental investigation described in Note 3 in the “Notes to Consolidated Financial Statements.” Although this investigation is expected to entail significant expense over the next several years, management does not believe, based on information available to the Company at this time, that the costs of this investigation or any other contingent liabilities relating to environmental matters will have a material adverse effect on the Company. However, there can be no assurance that a significant environmental liability will not be incurred by the electric utilities, including with respect to the Honolulu Harbor environmental investigation.

Prior to extending a loan secured by real property, ASB conducts due diligence to assess whether or not the property may present environmental risks and potential cleanup liability. In the event of default and foreclosure of a loan, ASB may become the owner of the mortgaged property. For that reason, ASB seeks to avoid lending upon the security of, or acquiring through foreclosure, any property with significant potential environmental risks; however, there can be no assurance that ASB will successfully avoid all such environmental risks.

Electric utility

Regulation of electric utility rates. The PUC has broad discretion in its regulation of the rates charged by HEI’s electric utility subsidiaries and in other matters. Any adverse D&O by the PUC concerning the level or method of determining electric utility rates, the authorized returns on equity or other matters, or any prolonged delay in rendering a D&O in a rate or other proceeding, could have a material adverse effect on the Company’s results of operations and financial condition. Upon a showing of probable entitlement, the PUC is required to issue an interim D&O in a rate case within 10 months from the date of filing a completed application if the evidentiary hearing is completed (subject to extension for 30 days if the evidentiary hearing is not completed). There is no time limit for rendering a final D&O. Interim rate increases are subject to refund with interest, pending the final outcome of the

23

case. At December 31, 2002, HECO and its subsidiaries had recognized $16 million of revenues with respect to interim orders regarding certain integrated resource planning costs, which revenues are subject to refund, with interest, to the extent they exceed the amounts allowed in final orders.

Management cannot predict with certainty when D&Os in future rate cases will be rendered or the amount of any interim or final rate increase that may be granted. There are no rate cases pending at this time. HECO, however, has committed to file a rate increase application using a 2003 or 2004 test year.

The rate schedules of the electric utility subsidiaries include energy cost adjustment clauses under which electric rates charged to customers are automatically adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power. In 1997 PUC decisions approving the electric utilities’ fuel supply contracts, the PUC noted that, in light of the length of the fuel supply contracts and the relative stability of fuel prices, the need for continued use of energy cost adjustment clauses would be the subject of investigation in a generic docket or in a future rate case. The electric utility subsidiaries believe that the energy cost adjustment clauses continue to be necessary. These clauses were continued in the most recent HELCO and MECO rate cases (final D&O’s issued in February 2001 and April 1999, respectively).

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

Fuel oil and purchased power. The electric utilities rely on fuel oil suppliers and independent power producers to deliver fuel oil and power, respectively. The Company estimates that 77% of the net energy generated and purchased by HECO and its subsidiaries in 2003 will be generated from the burning of oil. Purchased KWHs provided approximately 38.0% of the total net energy generated and purchased in 2002 compared to 39.0% in 2001 and 36.4% in 2000.

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

Other regulatory and permitting contingencies. Many public utility projects require PUC approval and various permits (e.g., environmental and land use permits) from other agencies. Delays in obtaining PUC approval or permits can result in increased costs. If a project does not proceed or if the PUC disallows costs of the project, the project costs may need to be written off in amounts that could have a material adverse effect on the Company. The following two major capital improvement utility projects, the Keahole project and the Kamoku-Pukele transmission line, have encountered opposition and the Keahole project has been seriously delayed.

Keahole project. In 1991, HELCO began planning to meet increased electric generation demand forecasted for 1994. HELCO’s plans were to install at its Keahole power plant two 20 MW combustion turbines (CT-4 and CT-5), followed by an 18 MW heat steam recovery generator, at which time these units would be converted to a 56 MW (net) dual-train combined-cycle unit. The timing of the installation of HELCO’s phased units has been revised on several occasions due to delays in obtaining an air permit and a land use permit amendment, in addition to delays caused by the commencement of lawsuits and administrative proceedings, many of which are on appeal or

24

otherwise have not been finally resolved. See Note 3 in the “Notes to Consolidated Financial Statements” for a more detailed description of the history and status of this project.

In September 2000, the Third Circuit Court of the State of Hawaii (Circuit Court) ruled that, absent a legal or equitable extension properly authorized by the Board of Land and Natural Resources (BLNR), HELCO’s further construction of CT-4 and CT-5 could not proceed because HELCO had not completed construction within the three-year construction period the Circuit Court found to be applicable to the project, unless the BLNR extended the construction period. HELCO subsequently obtained a BLNR order extending the construction period, but the Circuit Court then ruled, on September 19, 2002, that the BLNR did not have authority to grant the extension. As a result of this ruling, the construction of CT-4 and CT-5 has been suspended.

HELCO has appealed to the Hawaii Supreme Court both the Circuit Court 2000 ruling that there was a three-year construction period that had expired and the Circuit Court’s later ruling that BLNR could not extend the construction period. HELCO also filed motions to expedite the appeal and to stay the Circuit Court’s ruling pending the appeal. The Hawaii Supreme Court has denied the motion to expedite the appeal and the motion to stay the Circuit Court’s ruling pending appeal. In early 2003, the Hawaii Supreme Court also ruled that the appeal from the Circuit Court’s ruling in 2000 that the construction period had expired was not timely (even though the Circuit Court ruled at the time that its Order could not yet be appealed) and dismissed the appeal. HELCO cannot predict when its appeal of the Circuit Court’s ruling that the BLNR lacked authority to extend the construction deadline will be decided.

HELCO continues to consider other options that may allow HELCO to complete the installation of CT-4 and CT-5 (including seeking a land use reclassification of the Keahole site from the State Land Use Commission). If none of these options is ultimately successful and HELCO does not prevail on its appeal, HELCO may be unable to complete the installation of CT-4 and CT-5. The recovery of costs relating to CT-4 and CT-5 are subject to the rate-making process governed by the PUC. Management believes no adjustment to costs incurred to put CT-4 and CT-5 into service is required as of December 31, 2002. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HELCO may be required to write off a material portion of the costs incurred in its efforts to put these units into service whether or not CT-4 and CT-5 are installed. As of December 31, 2002, HELCO’s costs incurred in its efforts to put CT-4 and CT-5 into service and to support existing units (excluding costs the PUC permitted to be transferred to plant-in-service for pre-air permit facilities in HELCO’s most recent rate case) amounted to approximately $82 million, including $32 million for equipment and material purchases, $30 million for planning, engineering, permitting, site development and other costs and $20 million for AFUDC charged to the project prior to HELCO’s decision to discontinue the further accrual of AFUDC on CT-4 and CT-5. HELCO discontinued the accrual of AFUDC effective December 1, 1998, due in part to the delays and the potential for further delays. In addition to the $82 million in construction in progress, construction and/or purchase commitments related to CT-4 and CT-5 outstanding as of December 31, 2002 are estimated at approximately $0.6 million. See “HELCO Power Situation” in Note 3 of the “Notes to Consolidated Financial Statements.”

Kamoku-Pukele transmission line. HECO has for some time been expending efforts to address future potential line overloads in its two major corridors (Northern and Southern) transmitting bulk power to the Honolulu/East Oahu area, and to improve the reliability of the Pukele substation at the end of the Northern corridor. HECO planned to construct a part underground/part overhead 138 kv transmission line from the Kamoku substation to the Pukele substation in order to close the gap between the Southern and Northern transmission corridors and provide a third 138 kv transmission line to the Pukele substation. Construction of the proposed Kamoku to Pukele transmission line in its proposed location required the BLNR to approve a Conservation District Use Permit (CDUP) for the overhead portion of the line that would have been in conservation district lands. On June 28, 2002, the BLNR issued a ruling denying HECO’s request for the CDUP.

HECO continues to believe that the proposed project is needed. HECO is evaluating alternative ways to accomplish the project, and possible future actions to expedite PUC review of the alternatives and the need for the project. As of December 31, 2002, the accumulated costs related to the Kamoku to Pukele transmission line amounted to $17 million, including $12 million for planning, engineering and permitting costs and $5 million for AFUDC. These costs are recorded in construction in progress. The recovery of costs relating to the Kamoku to Pukele transmission line project is subject to the rate-making process governed by the PUC. Management believes no adjustment to costs incurred to put the Kamoku to Pukele transmission line into service is required as of December 31, 2002. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HECO may be required to write off a material portion or all of the costs incurred in its efforts

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to put the Kamoku to Pukele transmission line into service whether or not the line is installed. See “Oahu transmission system” in Note 3 of the “Notes to Consolidated Financial Statements.”

Bank

Regulation of ASB. ASB is subject to examination and comprehensive regulation by the OTS and the FDIC, and is subject to reserve requirements established by the Board of Governors of the Federal Reserve System. By reason of the regulation of its subsidiary, ASB Realty Corporation, ASB is also subject to regulation by the Hawaii Commissioner of Financial Institutions. Regulation by these agencies focuses in large measure on the adequacy of ASB’s capital and the results of periodic “safety and soundness” examinations conducted by the OTS.

Capital requirements. The OTS, which is ASB’s principal regulator, administers two sets of capital standards—minimum regulatory capital requirements and prompt corrective action requirements. The FDIC also has prompt corrective action capital requirements. As of December 31, 2002, ASB was in compliance with OTS minimum regulatory capital requirements and was “well-capitalized” within the meaning of OTS prompt corrective action regulations and FDIC capital regulations, as follows:

• ASB met applicable minimum regulatory capital requirements (noted in parentheses) at December 31, 2002 with a tangible capital ratio of 6.7% (1.5%), a core capital ratio of 6.7% (4.0%) and a total risk-based capital ratio of 14.7% (8.0%).

• ASB met the capital requirements to be generally considered “well-capitalized” (noted in parentheses) at December 31, 2002 with a leverage ratio of 6.7% (5.0%), a Tier-1 risk-based capital ratio of 13.5% (6.0%) and a total risk-based capital ratio of 14.7% (10.0%).

The purpose of the prompt corrective action capital requirements is to establish thresholds for varying degrees of oversight and intervention by regulators. Declines in levels of capital, depending on their severity, will result in increasingly stringent mandatory and discretionary regulatory consequences. Capital levels may decline for any number of reasons, including reductions that would result if there were losses from operations, deterioration in collateral values or the inability to dispose of real estate owned (such as by foreclosure) within five years. The regulators have substantial discretion in the corrective actions they might direct and could include restrictions on dividends and other distributions that ASB may make to its shareholders and the requirement that ASB develop and implement a plan to restore its capital. Under an agreement with regulators entered into by HEI when it acquired ASB, HEI could be required to contribute up to an additional $28 million, if necessary to maintain ASB’s capital position.

Examinations. ASB is subject to periodic “safety and soundness” examinations by the OTS. In conducting its examinations, the OTS utilizes the Uniform Financial Institutions Rating System adopted by the Federal Financial Institutions Examination Council, which system utilizes the “CAMELS” criteria for rating financial institutions. The six components in the rating system are: Capital adequacy, Asset quality, Management, Earnings, Liquidity and Sensitivity to market risk. The OTS examines and rates each CAMELS component. An overall CAMELS rating is also given, after taking into account all of the component ratings. A financial institution may be subject to formal regulatory or administrative direction or supervision such as a “memorandum of understanding” or a “cease and desist” order following an examination if its CAMELS rating is not satisfactory. An institution is prohibited from disclosing the OTS’s report of its safety and soundness examination or the component and overall CAMELS rating to any person or organization not officially connected with the institution as officer, director, employee, attorney, or auditor, except as provided by regulation.

The Federal Deposit Insurance Act, as amended, addresses the safety and soundness of the deposit insurance system, supervision of depository institutions and improvement of accounting standards. Pursuant to this Act, federal banking agencies have promulgated regulations that affect the operations of ASB and its holding companies (e.g., standards for safety and soundness, real estate lending, accounting and reporting, transactions with affiliates and loans to insiders). FDIC regulations restrict the ability of financial institutions that fail to meet relevant capital measures to engage in certain activities, such as offering interest rates on deposits that are significantly higher than the rates offered by competing institutions and offering “pass-through” insurance coverage (i.e., insurance coverage that passes through to each owner/beneficiary of the applicable deposit) for the deposits of most employee benefit plans (i.e., $100,000 per individual participant, not $100,000 per plan). As of December 31, 2002, ASB was “well-capitalized” and thus not subject to these restrictions.

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Qualified Thrift Lender status. In order to maintain its status as a “qualified thrift lender” (QTL), ASB is required to maintain at least 65% of its assets in “qualified thrift investments,” which include housing-related loans as well as certain small business loans, education loans, loans made through credit card accounts and a basket (not exceeding 20% of total assets) of other consumer loans and other assets. Savings associations that fail to maintain QTL status are subject to various penalties, including limitations on their activities. In ASB’s case, the activities of HEI, HEIDI and HEI’s other subsidiaries would also be subject to restrictions, and a failure or inability to comply with those restrictions could effectively result in the required divestiture of ASB.

Federal Thrift Charter. In November 1999, Congress passed the Gramm-Leach-Bliley Act of 1998 (the Gramm Act), under which banks, insurance companies and investment firms can compete directly against each other, thereby allowing “one-stop shopping” for an array of financial services. Although the Gramm Act further restricts the creation of so-called “unitary savings and loan holding companies” (i.e., companies such as HEI whose subsidiaries include one or more savings associations and one or more nonfinancial subsidiaries), the unitary savings and loan holding company relationship among HEI, HEIDI and ASB is “grandfathered” under the Gramm Act so that HEI and its subsidiaries will be able to continue to engage in their current activities so long as ASB maintains its QTL status. Under the Gramm Act, any proposed acquisition of ASB would have to satisfy applicable statutory and regulatory requirements and potential acquirers of ASB would most likely be limited to companies that are already qualified as, or capable of qualifying as, either a traditional savings and loan association holding company or a bank holding company, or as one of the newly authorized financial holding companies permitted under the Gramm Act.

Material estimates and critical accounting policies

In preparing the consolidated financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. Actual results could differ significantly from those estimates.

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

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

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

Consolidated

Investment securities. Debt securities that the Company intends to and has the ability to hold to maturity are classified as held-to-maturity securities and reported at amortized cost. Marketable equity securities and debt securities that are bought and held principally for the purpose of selling them in the near term are classified as trading securities and reported at fair value, with unrealized gains and losses included in earnings. Marketable equity securities and debt securities not classified as either held-to-maturity or trading securities are classified as available-for-sale securities and reported at fair value, with unrealized gains and losses excluded from earnings and reported in a separate component of stockholders’ equity.

For securities that are not trading securities, declines in value determined to be other than temporary are included in earnings and result in a new cost basis for the investment. The specific identification method is used in determining realized gains and losses on the sales of securities.

ASB owns private-issue mortgage-related securities as well as mortgage-related securities issued by the Federal Home Loan Mortgage Corporation (FHLMC), Government National Mortgage Association (GNMA) and FNMA, all of which are classified as available-for-sale. Market prices for the private-issue mortgage-related securities are not readily available from standard pricing services, so prices are obtained from dealers who are

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specialists in those markets. The prices of these securities may be influenced by factors such as market liquidity, corporate credit considerations of the underlying collateral, the levels of interest rates, expectations of prepayments and defaults, limited investor base, market sector concerns and overall market psychology. Adverse changes in any of these factors may result in additional losses. Market prices for the mortgage-related securities issued by FHLMC, GNMA and FNMA are available from most third party securities pricing services. ASB obtains market prices for these securities from a third party financial services provider. At December 31, 2002, ASB had mortgage-related securities issued by FHLMC, GNMA and FNMA valued at $1.9 billion and private-issue mortgage-related securities valued at $0.9 billion.

Because quoted market prices are not available, HEI’s income notes are valued by discounting the expected future cash flows using current market rates for similar investments by an outside party. The fair value of these securities may vary substantially from period to period because of changes in market interest rates and in the performance of the assets underlying such securities. At December 31, 2002, HEI had income notes valued at $8.0 million, compared to a valuation of these notes of $15.6 million at December 31, 2001.

Property, plant and equipment. Property, plant and equipment are reported at cost. Self-constructed electric utility plant includes engineering, supervision, and administrative and general costs, and an allowance for the cost of funds used during the construction period. These costs are recorded in construction in progress and are transferred to property, plant and equipment when construction is completed and the facilities are either placed in service or become useful for public utility purposes. Upon the retirement or sale of electric utility plant, no gain or loss is recognized. The cost of the plant retired or sold and the cost of removal (net of salvage value) previously provided through depreciation are charged to accumulated depreciation.

Management believes that the PUC will allow recovery of property, plant and equipment in its electric rates. If the PUC does not allow recovery of any such costs, the electric utility would be required to write off the disallowed costs at that time. See the discussion above concerning costs recorded in construction in progress for CT-4 and CT-5 at Keahole and the proposed Kamoku-Pukele transmission line under “Certain factors that may affect future results and financial condition–Other regulatory and permitting contingencies.”

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

The Company’s reported costs of providing retirement benefits (described in Note 8 in the “Notes to Consolidated Financial Statements”) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. For example, pension and other postretirement benefit costs are impacted by actual employee demographics (including age and compensation levels), the level of contributions to the plans and earnings on plan assets. Changes made to the provisions of the plans may also impact current and future costs. (No changes were made to the retirement benefit plans’ provisions in 2002, 2001 and 2000 that have had a significant impact on recorded retirement benefit plan amounts.) Costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used.

As a result of the factors listed above, significant portions of pension and other postretirement benefit costs recorded in any period do not reflect the actual benefits provided to plan participants. For 2002 and 2001, the Company recorded other postretirement benefit expense, net of amounts capitalized, of approximately $4 million and $2 million, respectively, in accordance with the provisions of SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” Actual payments of benefits made to retirees during 2002 and 2001 were $6 million and $7 million, respectively. In accordance with SFAS No. 87, “Employers’ Accounting for Pensions,” changes in pension obligations associated with the factors noted above may not be immediately recognized as pension costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. For 2002 and 2001, the Company recorded non-cash pension income, net of amounts capitalized, of approximately $11 million and $17 million, respectively, and paid benefits of $36 million and $34 million, respectively.

The assumptions used by management in making benefit and funding calculations are based on current economic conditions. Changes in economic conditions will impact the underlying assumptions in determining retirement benefit costs on a prospective basis. In selecting an assumed discount rate, the Company considers the Moody’s Aa and Aaa Daily Long-Term Corporate Bond Yield Averages, as well as yields for 20 and 30 year

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Treasury strips. In selecting an assumed rate of return on plan assets, the Company considers economic forecasts for the types of investments held by the plan and the past performance of plan assets.

As presented in Note 8 in the “Notes to Consolidated Financial Statements,” the Company has revised key assumptions at December 31, 2002 compared to December 31, 2001. Such changes will not have an impact on reported costs in 2002; however, for future years, such changes will have a significant impact. Based upon the revised assumptions (decreasing the discount rate 50 basis points to 6.75% and the long-term rate of return on assets 100 basis points to 9.0% as of December 31, 2002 compared to December 31, 2001), the Company estimates that retirement benefits expense, net of amounts capitalized and income taxes, will be $12 million in 2003 as compared to net retirement benefits income of $4 million in 2002 (or $16 million less net income). Of the $12 million of net retirement benefits expense, it is projected that HECO and its subsidiaries will record an estimated $8 million in 2003 as compared to net retirement benefits income of $6 million in 2002 (or $14 million less net income). In determining the retirement benefit costs, these assumptions can change from period to period, and such changes could result in material changes to these estimated amounts.

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

The following tables reflect the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage and constitute “forward-looking statements.” While the tables below reflect an increase or decrease in the percentage for each assumption, the Company and its actuaries expect that the inverse of these changes would impact the projected benefit obligation (PBO) and 2003 net income in the opposite direction. Each sensitivity below reflects an evaluation of the change based solely on a change in that assumption as well as a related change in the contributions to the postretirement benefits plan.

Actuarial assumption	Change in assumption		Impact on PBO		Impact on 2003 net income
	(in millions)
Pension benefits
Discount rate	(0.5	)%	$	51.8	$	(2.5	)
Rate of return on plan assets	(0.5	)		—		(1.4	)
Other benefits
Discount rate	(0.5	)		9.3		(0.2	)
Health care cost trend rate	0.5			2.0		(0.1	)
Rate of return on plan assets	(0.5	)		—		(0.2	)

As a result of its plan asset return experience in 2002, at December 31, 2002, the Company was required to recognize an additional minimum liability of $9 million as prescribed by SFAS No. 87. The liability was recorded partly as an intangible asset and partly as a reduction to common equity through a charge to other comprehensive income, and did not affect net income for 2002. The charge to other comprehensive income would be restored through common equity in future periods to the extent the fair value of trust assets exceeded the accumulated benefit obligation.

Environmental expenditures. In general, environmental contamination treatment costs are charged to expense, unless it is probable that the PUC would allow such costs to be recovered in future rates, in which case such costs would be capitalized as regulatory assets. Also, environmental costs are capitalized if the costs extend the life, increase the capacity, or improve the safety or efficiency of property; the costs mitigate or prevent future environmental contamination; or the costs are incurred in preparing the property for sale. Liabilities are recorded when environmental assessments and/or remedial efforts are probable, and the cost can be reasonably estimated. Estimated costs are based upon an expected level of contamination and remediation efforts. Should the level of contamination and remediation efforts be different than initially expected, the ultimate costs will differ. See “Environmental regulation” in Note 3 of the “Notes to Consolidated Financial Statements” for a description of the Honolulu Harbor investigation.

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

Governmental tax authorities could challenge a tax return position taken by management, and such challenges might not be raised and finally resolved until several years after the events in question. If the Company’s position does not prevail, the Company’s results of operations and financial condition may be adversely affected as the related deferred or current income tax asset would be impaired.

In March 1998, ASB formed a subsidiary, ASB Realty Corporation, which elects to be taxed as a REIT. This reorganization has reduced Hawaii bank franchise taxes, net of federal income taxes, of HEIDI and ASB by $17 million for 2002 and prior years. The State of Hawaii Department of Taxation has challenged ASB’s position and has issued notices of tax assessment for 1999, 2000 and 2001. ASB believes that its tax position is proper and, in October 2002, filed an appeal with the State Board of Review, First Taxation District. No provision for Hawaii bank franchise taxes has been made since 1998. If the state’s position prevails, ASB would suffer adverse state income tax consequences. See Note 9 of the “Notes to Consolidated Financial Statements” for further information.

The Company’s loss of its investment in East Asia Power Resources Corporation of approximately $90 million was recognized in 2000 for financial reporting purposes and was included in HEI’s 2001 income tax return as an ordinary loss. HEI has requested that the Internal Revenue Service confirm that the treatment of this loss, as an ordinary loss, was proper.

Electric utility

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

Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. As of December 31, 2002, regulatory assets amounted to $106 million. These regulatory assets are itemized in Note 3 of the “Notes to Consolidated Financial Statements.” Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment. Because current rates include the recovery of existing regulatory assets and rates in effect allow the utilities to earn a reasonable rate of return, management believes the existing regulatory assets are probable of recovery. This determination assumes continuation of the current political and regulatory climate in Hawaii, and is subject to change in the future.

Management believes HECO and its subsidiaries’ operations currently satisfy the SFAS No. 71 criteria. However, if events or circumstances should change so that those criteria are no longer satisfied, management believes that a material adverse effect on the Company’s results of operations and financial position may result as regulatory assets would be charged to expense.

Electric utility revenues. Electric utility revenues are based on rates authorized by the PUC and include revenues applicable to energy consumed in the accounting period but not yet billed to the customers. At December 31, 2002, revenues applicable to energy consumed, but not yet billed to the customers, amounted to $60 million.

Revenue amounts recorded pursuant to a PUC interim order are subject to refund, with interest, pending a final order. At December 31, 2002, HECO and its subsidiaries had recognized $16 million of revenues with respect to interim orders regarding certain integrated resource planning costs, which revenues are subject to refund, with interest, to the extent they exceed the amounts allowed in final orders. If a refund were required, the revenues to be refunded would be immediately reversed on the income statement. The Consumer Advocate has objected to the recovery of $1.9 million (before interest) of the $8.5 million of integrated resource planning costs incurred from 1995 through 1998 and in 2001, and the PUC’s decision is pending on this matter. The Consumer Advocate has not stated its position on the recovery of the $1.5 million of integrated resource planning costs incurred from 1999 through 2000.

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The rate schedules of the electric utility subsidiaries include energy cost adjustment clauses under which electric rates are adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power. If the energy cost adjustment clauses were discontinued, the electric utilities’ results of operations could fluctuate significantly as a result of increases and decreases in fuel oil and purchased energy prices. In 1997 PUC decisions approving the electric utilities’ fuel supply contracts, the PUC noted that, in light of the length of the fuel supply contracts and the relative stability of fuel prices, the need for continued use of energy cost adjustment clauses would be the subject of investigation in a generic docket or in a future rate case. HECO and its subsidiaries believe that the energy cost adjustment clauses continue to be necessary. These clauses were continued in the most recent HELCO and MECO rate cases.

Bank

Allowance for loan losses. ASB maintains an allowance for loan losses that it believes is adequate to absorb estimated losses on all loans. The level of allowance for loan losses is based on a continuing assessment of existing risks in the loan portfolio, historical loss experience, changes in collateral values, and current and anticipated economic conditions. For business and commercial real estate loans, a risk rating system is used. Loans are rated based on the degree of risk at origination and periodically thereafter, as appropriate. A credit review department performs an evaluation of these loan portfolios to ensure compliance with the internal risk rating system and timeliness of rating changes. Adverse changes in any of the risk factors could result in higher charge-offs and loan loss provisions. When loans are deemed impaired, the amount of impairment is measured based on the present value of expected future cash flows discounted at the loan’s effective interest rate and the fair value of the collateral securing the loan. Impairment losses are charged to the provision for loan losses and included in the allowance for loan losses.

For the remaining loans receivable portfolio, allowance for loan loss allocations are determined based on a loss migration analysis. The loss migration analysis determines potential loss factors based on historical loss experience for homogeneous loan portfolios.

At December 31, 2002, ASB’s allowance for loan losses was $45.4 million and ASB had $15.8 million of loans on nonaccrual status (in general, delinquent more than 90 days). In 2002, ASB’s provision for loan losses was $9.8 million.

Quantitative and Qualitative Disclosures about Market Risk

The Company manages various market risks in the ordinary course of business, including credit risk and liquidity risk, and believes its exposures to these risks are not material as of December 31, 2002. Because the Company does not have a portfolio of trading assets, the Company is not exposed to market risk from trading activities.

The Company is exposed to some commodity price risk primarily related to its fuel supply and IPP contracts and foreign currency exchange rate risk. The Company’s commodity price risk is mitigated by the electric utilities’ energy cost adjustment clauses in their rate schedules. The Company’s remaining investment in the Philippines as of December 31, 2002 is the investment in 22% of the common stock of CEPALCO, which the Company has available for sale. The sale price may be affected by the Philippine Peso/U.S. dollar exchange rate. The Company currently has no hedges against its commodity price risk and foreign currency exchange rate risks.

The Company considers interest rate risk to be a very significant market risk as it could potentially have a significant effect on the Company’s results of operations and financial condition especially as it relates to ASB. Interest rate risk can be defined as the exposure of the Company’s earnings to adverse movements in interest rates.

HEI has entered into two swap agreements to manage its exposure to interest rate risk. In general, HEI issues primarily fixed-rate long-term debt to balance its short-term debt, which in essence is variable-rate debt by virtue of its short-term nature. In April 2000, during a period of rising interest rates, HEI was able to issue $100 million of its variable-rate medium-term notes and simultaneously enter into a swap agreement, which effectively fixed the interest rate on the $100 million of debt at 7.995% until maturity in April 2003. In June 2001, during a period of falling interest rates, HEI had the opportunity to lower its interest payments on these same medium-term notes and entered into a swap agreement which changed $100 million of effectively 7.995% fixed-rate debt to variable-rate

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debt (adjusted quarterly based on changes in the London InterBank Offered Rate (LIBOR) indices). Other than these swaps, the Company does not currently use derivatives to manage interest rate risk.

Bank

The Company’s success is dependent, in part, upon ASB’s ability to manage interest rate risk. For ASB, interest-rate risk is the sensitivity of net interest income and the market value of interest-sensitive assets and liabilities to changes in interest rates. The primary source of interest-rate risk is the mismatch in timing between the maturity or repricing of interest-sensitive assets and liabilities. Large mismatches could adversely affect ASB’s earnings and the market value of its interest-sensitive assets and liabilities in the event of significant changes in the level of interest rates.

ASB’s Asset/Liability Management Committee (ALCO) serves as the group charged with the responsibility of managing interest rate risk and of carrying out the overall asset/liability management objectives and activities of ASB as approved by the ASB Board of Directors. ALCO establishes policies that monitor and coordinate ASB’s assets and liabilities.

ASB’s interest-rate risk profile is strongly influenced by the bank’s primary business of making fixed-rate residential mortgage loans and taking in retail deposits. The fixed-rate residential mortgage loans originated and retained by ASB are characterized by fixed interest rates and long average lives, but also have the potential to prepay at any time without penalty. The option to prepay is usually exercised by borrowers in low interest rate environments, significantly shortening the average lives of these assets. A majority of ASB’s liabilities consists of retail deposits. The interest rates paid on many of the retail deposit accounts can be adjusted in response to changes in market interest rates. Other retail deposit accounts with fixed interest rates typically have stated maturities much shorter than that of a 30-year mortgage. As a result, these liabilities will tend to reprice more frequently than the fixed-rate mortgage assets.

The typical result of this combination of assets and liabilities is to create a “liability sensitive” interest rate risk profile. In a rising interest-rate environment, the average rate on ASB’s liabilities will tend to increase faster than the average rate on the assets, causing a reduction in net interest spread and net interest income. In a falling interest-rate environment, the opposite happens: the average rate on the bank’s liabilities will tend to decrease faster than the average rate on the bank’s assets, causing an increase in net interest spread and net interest income. This volatility in net interest spread and net interest income represents one measure of interest rate risk, and the degree of volatility is dependent on the magnitude of the mismatch in the amount and timing of maturing or repricing interest-sensitive assets and interest-sensitive liabilities.

Since ASB’s primary business of making fixed-rate residential real estate loans and taking in retail deposits does not always result in the optimum mix of assets and liabilities for the management of net interest income and interest rate risk, other tools must be employed. Chief among these is use of the investment portfolio to secure asset types that may not be available in significant amounts through originations. Included in this area are adjustable-rate mortgage-related securities, floating LIBOR-based securities, balloon or 15-year mortgage-related securities, and short average life collateralized mortgage obligations (CMOs). On the liability side, a shortage of retail deposits in desired maturities is made up through FHLB advances and other borrowings to meet asset/liability management needs.

Use of investments, FHLB advances and securities sold under agreements to repurchase, while efficient, is not as profitable as ASB’s own lending and deposit taking activities. In this regard, ASB is building its portfolio of consumer, business banking and commercial real estate loans, which generally earn higher rates of interest and have maturities shorter than residential real estate loans. The origination of consumer, business banking and commercial real estate loans involves risks different from those associated with originating residential real estate loans. For example, credit risk associated with consumer, business banking and commercial real estate loans is generally higher than for mortgage loans, the sources and level of competition may be different and, compared to residential real estate lending, the making of business banking and commercial real estate loans is a relatively new business for ASB. These different risk factors are considered in the underwriting and pricing standards established by ASB for its consumer, business banking and commercial real estate loans.

ASB currently does not use any interest-rate derivatives to manage interest-rate risk.

Management measures interest-rate risk using simulation analysis with an emphasis on measuring changes in net interest income and the market value of interest-sensitive assets and liabilities in different interest-rate

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environments. The simulation analysis is performed using a dedicated asset/liability management software system. During the year, the bank upgraded its systems and purchased a new asset/liability management system enhanced with a mortgage prepayment model and a CMO database. The new simulation software is capable of generating scenario-specific cash flows for all instruments using the specified contractual information for each instrument and product specific prepayment assumptions. This new software has enhanced the bank’s ability to perform net interest income and market value sensitivity analysis. Accordingly, ASB has changed its market risk analysis from a tabular presentation to a presentation of net interest income and market value sensitivity. HEI has also changed the market risk analysis for its other segments from a tabular presentation to a presentation of net interest expense sensitivity.

Net interest income (NII) sensitivity analysis measures the change in ASB’s twelve-month, pre-tax NII in alternate interest rate scenarios. NII sensitivity is measured as the change in NII in alternative interest-rate scenarios as a percentage of the base case NII. The base case interest-rate scenario is established using the current yield curve and assumes interest rates remain constant over the next twelve months. The alternate scenarios are created by assuming immediate and sustained parallel shocks of the yield curve in increments of +/- 100 basis points. The simulation model forecasts scenario-specific principal and interest cash flows for the interest-bearing assets and liabilities, and the NII is calculated for each scenario. Key balance sheet modeling assumptions used in the NII sensitivity analysis include: the size of the balance sheet remains relatively constant over the simulation horizon and maturing assets or liabilities are reinvested in similar instruments in order to maintain the current mix of the balance sheet. In addition, assumptions are made about the prepayment behavior of mortgage-related assets and the pricing characteristics of new assets and liabilities. The simulation does not contemplate any actions that ASB management might undertake in response to changes in interest rates. These assumptions are used for analytical purposes only and do not represent management’s views of future market movements or future earnings. Rather, these assumptions are intended to help management identify potential exposures in ASB’s current balance sheet and formulate appropriate strategies for managing interest rate risk.

ASB’s net portfolio value (NPV) ratio is a measure of the economic capitalization of the bank. The NPV ratio is the ratio of the net portfolio value of ASB to the present value of expected net cash flows from existing assets. Net portfolio value represents the theoretical market value of ASB’s net worth and is defined as the present value of expected net cash flows from existing assets minus the present value of expected cash flows from existing liabilities plus the present value of expected net cash flows from existing off-balance sheet contracts. The NPV ratio is calculated by ASB pursuant to guidelines established by the OTS in Thrift Bulletin 13a. Key assumptions used in the calculation of ASB’s NPV ratio include the prepayment behavior of loans and investments, the possible distribution of future interest rates, future pricing spreads for assets and liabilities and the rate and balance behavior of deposit accounts with indeterminate maturities. Typically, if the value of the bank’s assets grows relative to the value of the bank’s liabilities, the NPV ratio will increase. Conversely, if the value of the bank’s liabilities grows relative to the value of the bank’s assets, the NPV ratio will decrease. The NPV ratio is calculated in multiple scenarios. As with the NII simulation, the base case is represented by the current yield curve. Alternate scenarios are created by assuming immediate parallel shifts in the yield curve in increments of +/- 100 basis points.

The NPV ratio sensitivity measure is the change from the NPV ratio calculated in the base case to the NPV ratio calculated in the alternate rate scenarios. In general, high sensitivity measures, or large decreases in the NPV ratio, are indicative of large imbalances between the maturity or repricing of interest sensitive assets and interest sensitive liabilities. Low NPV ratio sensitivity measures, or small decreases in the NPV ratio, are indicative of a better match between the timing and amount of the maturity or repricing of assets and liabilities. The sensitivity measure alone is not necessarily indicative of the interest-rate risk of an institution, as institutions with high levels of capital may be able to support a high sensitivity measure. This measure is evaluated in conjunction with the NPV ratio calculated in each scenario.

33

ASB’s interest-rate risk sensitivity measures as of December 31, 2002 and 2001 constitute “forward-looking statements” and were as follows:

	December 31
	2002						2001
	Change in NII		NPV ratio		NPV ratio sensitivity (change from base case in basis points)		Change in NII		NPV ratio	NPV ratio sensitivity (change from base case in basis points)
Change in interest rates (basis points)
+300	1.9	%	7.90	%	(235	)	(4.5	)	6.10	(367	)
+200	3.0		9.15		(110	)	(3.0	)	7.45	(232	)
+100	3.3		10.01		(24	)	(1.5	)	8.60	(117	)
Base	—		10.25		—		—		9.77	—
-100	(5.7	)	10.02		(23	)	2.2		10.65	88

Management believes that ASB’s interest-rate risk position at December 31, 2002 represents a reasonable level of risk.

In the past, ASB’s NII profile has shown NII increasing in the falling rate scenarios and decreasing in the rising rate scenarios. That profile is typical of an institution that is “liability sensitive.” The current NII profile differs slightly – the bank is “asset-sensitive” over small changes in interest rates (< 100 basis points), and becomes “liability-sensitive” over larger changes in interest rates. This profile is due to the extremely low level of interest rates and fast prepayment speeds anticipated in the current interest rate environment. In the base case, the low level of interest rates causes the prepayment models to forecast very fast prepayment speeds for the mortgage assets. The high volume of repayments is assumed to be reinvested at the current, low level of interest rates, which causes the overall yield of the mortgage assets to decrease quickly. In the –100 basis point scenario, NII drops relative to the base case, as even faster prepayment forecasts and lower reinvestment rates cause the yield on mortgage assets to decline faster than in the base case. The yield on liabilities, however, does not fall as rapidly, as the low level of interest rates limits the ability to lower the rate on retail deposits. This causes net interest income to fall.

The NII increases in the +100 basis point scenario as slower prepayment speeds enable the mortgage assets to maintain their yield. The increase in interest income is slightly greater than the increase in interest expense and results in a slight improvement in the 12-month estimate of net interest income compared to the base case. In the +200 and +300 basis point scenarios, the profile becomes more like that of a “liability sensitive” institution. In these scenarios, slower prepayment speeds continue to reduce the runoff of the existing mortgage assets, which reduces the amount available for reinvestment at the higher market rates. This constrains the speed with which the yield on the mortgage asset portfolio can adjust upwards to market levels. At the same time, the yield on the liabilities continues to increase with each increase in the level of interest rates.

The computation of the prospective effects of hypothetical interest rate changes is based on numerous assumptions, including relative levels of market interest rates, loan prepayments, actual balance changes and pricing strategies, and should not be relied upon as indicative of future results. Furthermore, to the extent market conditions and other factors vary from the assumptions used in the simulation analysis, future results will differ from the simulation results.

The table below provides contractual balances of ASB’s on- and off-balance sheet financial instruments at the expected maturity dates as well as the estimated fair values of those on- and off-balance sheet financial instruments as of December 31, 2001 and constitutes “forward-looking statements.” The expected maturity categories take into consideration historical prepayment rates as well as actual amortization of principal and do not take into consideration reinvestment of cash. Various prepayment rates ranging from 12% to 47% were used in computing the expected maturity of ASB’s interest-sensitive assets as of December 31, 2001. The expected maturity categories for interest-sensitive core deposits take into consideration historical attrition rates based on core deposit studies. Core deposit attrition rates ranging from 14% to 32% were used in expected maturity computations for core deposits. Actual prepayment and attrition rates may differ from expected rates and may cause the actual maturities and principal repayments to differ from the expected maturities and principal repayments. The weighted-average interest rates for the various assets and liabilities presented are as of December 31, 2001. See Note 14 in

34

the “Notes to Consolidated Financial Statements” for descriptions of the methods and assumptions used to estimate fair value of each applicable class of financial instruments.

	Expected maturity/principal repayment
December 31, 2001	2002		2003		2004		2005		2006		There- after		Total		Estimated fair value
	(in millions)
Interest-sensitive assets
Mortgage loans and Mortgage-related securities
Adjustable rate	$	521	$	344	$	228	$	151	$	100	$	192	$	1,536	$	1,568
Average interest rate (%)		6.1		6.0		6.0		5.9		5.9		5.9		6.0
Fixed rate—one-to-four family residential		535		343		265		225		196		1,498		3,062		3,107
Average interest rate (%)		7.4		7.1		6.9		6.8		6.8		6.7		6.9
Fixed rate—multi-family residential     and nonresidential		20		22		24		26		28		61		181		199
Average interest rate (%)		7.6		7.6		7.6		7.6		7.6		7.5		7.6
Consumer loans		76		57		43		54		14		—		244		254
Average interest rate (%)		9.1		9.5		9.9		8.8		11.2		—		9.4
Commercial loans		2		2		3		88		94		—		189		193
Average interest rate (%)		6.0		6.0		6.0		5.8		6.2		—		6.0
Interest-bearing deposits		319		—		—		—		—		—		319		319
Average interest rate (%)		1.7		—		—		—		—		—		1.7
Interest-sensitive liabilities
Passbook deposits		244		120		104		89		77		471		1,105		1,105
Average interest rate (%)		1.5		1.5		1.5		1.5		1.5		1.5		1.5
NOW and other demand deposits		168		127		98		76		59		242		770		770
Average interest rate (%)		0.2		0.2		0.2		0.2		0.2		0.2		0.2
Money market accounts		108		74		50		34		23		49		338		338
Average interest rate (%)		1.8		1.8		1.8		1.8		1.8		1.8		1.8
Certificates of deposit		951		105		114		222		58		17		1,467		1,490
Average interest rate (%)		3.8		4.2		5.8		6.4		5.9		4.7		4.4
FHLB advances		173		253		264		309		34		—		1,033		1,079
Average interest rate (%)		3.9		5.0		5.4		6.5		6.9		—		5.4
Other borrowings		648		—		35		—		—		—		683		685
Average interest rate (%)		2.7		—		4.7		—		—		—		2.8
Interest-sensitive off-balance sheet items
Loans serviced for others														1,057		13
Average interest rate (%)														6.7
Loan commitments and loans in process														64		(1	)
Average interest rate (%)														6.5
Unused lines and letters of credit														662		22
Average interest rate (%)														11.2

35

Other than bank

The Company’s general policy is to manage “other than bank” interest rate risk through use of a combination of short-term debt, long-term debt (primarily fixed-rate debt) and preferred securities. Net interest expense sensitivity analysis measures the change from the base case in twelve-month, pre-tax net interest expense in alternate interest rate scenarios. The base case interest-rate scenario is established using the current yield curve and assumes interest rates remain constant over the next twelve months. The alternate scenarios are created by assuming immediate and sustained parallel shocks of the yield curve in increments of +/- 100 basis points. The Company forecasts interest cash flows for the nonfixed-rate interest-bearing assets and liabilities (and assumes no changes in balances from December 31, except for $100 million of variable-rate debt that is expected to be refinanced to fixed-rate debt upon its maturity on April 15, 2003) and calculates net interest expense for each scenario. The calculation does not contemplate any actions that management might undertake in response to changes in interest rates. These assumptions are used for analytical purposes only and do not represent management’s views of future market movements or future earnings.

The Company’s “other than bank” interest rate risk sensitivity measure as of December 31, 2002 and 2001 constitutes “forward-looking statements” and was as follows:

	December 31
	2002			2001
	Change in net interest expense
	(in millions)
Change in interest rates (basis points)
+300	$	0.4		$	2.4
+200		0.3			1.6
+100		0.1			0.8
–100		(0.1	)		(0.8	)

The table below provides, on a tabular basis, information about the Company’s “other than bank” market sensitive financial instruments, including contractual balances at the stated maturity dates as well as the estimated fair values as of December 31, 2001, and constitutes “forward-looking statements.”

	Expected maturity
December 31, 2001	2002		2003		2004		2005		2006		There- after		Total		Estimated fair value
	(in millions)
Interest-sensitive liabilities
Long-term debt—variable rate	$	—	$	100	$	—	$	—	$	—	$	—	$	100	$	101
Average interest rate (%)		—		6.2		—		—		—		—		6.2
Long-term debt—fixed rate		74		36		1		37		110		788		1,046		1,013
Average interest rate (%)		6.8		6.7		6.8		6.7		7.5		6.0		6.2
HEI—and HECO—obligated preferred securities of trust subsidiaries		—		—		—		—		—		200		200		202
Average distribution rate (%)		—		—		—		—		—		8.0		8.0

36

Independent Auditors’ Report

The Board of Directors and Stockholders

Hawaiian Electric Industries, Inc.:

We have audited the accompanying consolidated balance sheets of Hawaiian Electric Industries, Inc. and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of income, changes in stockholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2002. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Hawaiian Electric Industries, Inc. and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

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

/s/    KPMG LLP

Honolulu, Hawaii

January 20, 2003

37

Consolidated Statements of Income

Hawaiian Electric Industries, Inc. and Subsidiaries

	Years ended December 31
	2002			2001			2000
	(in thousands, except per share amounts)
Revenues
Electric utility	$	1,257,176		$	1,289,304		$	1,277,170
Bank		399,255			444,602			450,882
Other		(2,730	)		(6,629	)		4,259
		1,653,701			1,727,277			1,732,311
Expenses
Electric utility		1,062,220			1,095,359			1,084,079
Bank		306,372			362,503			380,841
Other		18,676			13,242			9,858
		1,387,268			1,471,104			1,474,778
Operating income (loss)
Electric utility		194,956			193,945			193,091
Bank		92,883			82,099			70,041
Other		(21,406	)		(19,871	)		(5,599	)
		266,433			256,173			257,533
Interest expense—other than bank		(72,292	)		(78,726	)		(77,298	)
Allowance for borrowed funds used during construction		1,855			2,258			2,922
Preferred stock dividends of subsidiaries		(2,006	)		(2,006	)		(2,007	)
Preferred securities distributions of trust subsidiaries		(16,035	)		(16,035	)		(16,035	)
Allowance for equity funds used during construction		3,954			4,239			5,380
Income from continuing operations before income taxes		181,909			165,903			170,495
Income taxes		63,692			58,157			61,159
Income from continuing operations		118,217			107,746			109,336
Discontinued operations, net of income taxes
Loss from operations		—			(1,254	)		(63,592	)
Net loss on disposals		—			(22,787	)		—
Loss from discontinued operations		—			(24,041	)		(63,592	)
Net income	$	118,217		$	83,705		$	45,744
Basic earnings (loss) per common share
Continuing operations	$	3.26		$	3.19		$	3.36
Discontinued operations		—			(0.71	)		(1.95	)
	$	3.26		$	2.48		$	1.41
Diluted earnings (loss) per common share
Continuing operations	$	3.24		$	3.18		$	3.35
Discontinued operations		—			(0.71	)		(1.95	)
	$	3.24		$	2.47		$	1.40
Dividends per common share	$	2.48		$	2.48		$	2.48
Weighted-average number of common shares outstanding		36,278			33,754			32,545
Dilutive effect of stock options and dividend equivalents		199			188			142
Adjusted weighted-average shares		36,477			33,942			32,687

See accompanying “Notes to Consolidated Financial Statements.”

38

Consolidated Balance Sheets

Hawaiian Electric Industries, Inc. and Subsidiaries

	December 31
				2002					2001
	(in thousands)
ASSETS
Cash and equivalent				$	244,525				$	450,827
Accounts receivable and unbilled revenues, net					176,327					164,124
Available-for-sale investment and mortgage-related securities					1,960,288					1,613,710
Available-for-sale mortgage-related securities pledged for repurchase agreements					784,362					756,749
Held-to-maturity investment securities (estimated fair value $89,545 and $84,211)					89,545					84,211
Loans receivable, net					2,993,989					2,857,622
Property, plant and equipment, net
Land	$	45,212				$	45,005
Plant and equipment		3,297,357					3,178,822
Construction in progress		174,122					176,655
		3,516,691					3,400,482
Less—accumulated depreciation		(1,437,366	)		2,079,325		(1,332,979	)		2,067,503
Regulatory assets					105,568					111,376
Other					345,002					309,867
Goodwill and other intangibles					97,572					101,954
				$	8,876,503				$	8,517,943
LIABILITIES AND STOCKHOLDERS’ EQUITY
Liabilities
Accounts payable				$	134,416				$	119,850
Deposit liabilities					3,800,772					3,679,586
Securities sold under agreements to repurchase					667,247					683,180
Advances from Federal Home Loan Bank					1,176,252					1,032,752
Long-term debt					1,106,270					1,145,769
Deferred income taxes					235,431					185,436
Contributions in aid of construction					218,094					213,557
Other					257,315					293,742
					7,595,797					7,353,872
HEI and HECO-obligated preferred securities of trust subsidiaries directly or indirectly holding solely HEI and HEI-guaranteed and HECO and HECO-guaranteed subordinated debentures					200,000					200,000
Preferred stock of subsidiaries—not subject to mandatory redemption					34,406					34,406
					234,406					234,406
Stockholders’ equity
Preferred stock, no par value, authorized 10,000 shares; issued: none					—					—
Common stock, no par value, authorized 100,000 shares; issued and outstanding: 36,809 shares and 35,600 shares					839,503					787,374
Retained earnings					176,118					147,837
Accumulated other comprehensive income (loss)
Net unrealized gains (losses) on securities	$	35,914				$	(5,181	)
Minimum pension liability		(5,235	)		30,679		(365	)		(5,546	)
					1,046,300					929,665
				$	8,876,503				$	8,517,943

See accompanying “Notes to Consolidated Financial Statements.”

39

Consolidated Statements of Changes in Stockholders’ Equity

Hawaiian Electric Industries, Inc. and Subsidiaries

	Common stock				Retained earnings			Accumulated other comprehensive income (loss)			Total
	Shares	Amount
	(in thousands)
Balance, December 31, 1999	32,213	$	665,614		$	182,251		$	(279	)	$	847,586
Comprehensive income:
Net income	—		—			45,744			—			45,744
Net unrealized gains on securities arising during the period, net of taxes of $69	—		—			—			129			129
Minimum pension liability adjustment, net of tax benefits of $25	—		—			—			(40	)		(40	)
Comprehensive income	—		—			45,744			89			45,833
Issuance of common stock:
Dividend reinvestment and stock purchase plan	511		17,615			—			—			17,615
Retirement savings and other plans	267		8,704			—			—			8,704
Expenses and other	—		(8	)		—			—			(8	)
Common stock dividends ($2.48 per share)	—		—			(80,671	)		—			(80,671	)
Balance, December 31, 2000	32,991		691,925			147,324			(190	)		839,059
Comprehensive income:
Net income	—		—			83,705			—			83,705
Net unrealized losses on securities:
Cumulative effect of the adoption of SFAS No. 133, net of tax benefits of $1,294	—		—			—			(559	)		(559	)
Net unrealized losses arising during the period, net of taxes of $3,618	—		—			—			(1,748	)		(1,748	)
Add: reclassification adjustment for net realized gains included in net income, net of taxes of $1,391	—		—			—			(3,003	)		(3,003	)
Minimum pension liability adjustment, net of tax benefits of $29	—		—			—			(46	)		(46	)
Comprehensive income (loss)	—		—			83,705			(5,356	)		78,349
Issuance of common stock:
Public offering	1,500		56,550			—			—			56,550
Dividend reinvestment and stock purchase plan	694		26,310			—			—			26,310
Retirement savings and other plans	415		14,816			—			—			14,816
Expenses and other	—		(2,227	)		—			—			(2,227	)
Common stock dividends ($2.48 per share)	—		—			(83,192	)		—			(83,192	)
Balance, December 31, 2001	35,600		787,374			147,837			(5,546	)		929,665
Comprehensive income:
Net income	—		—			118,217			—			118,217
Net unrealized gains on securities:
Net unrealized gains arising during the period, net of taxes of $14,465	—		—			—			38,346			38,346
Add: reclassification adjustment for net realized losses included in net income, net of tax benefits of $1,440	—		—			—			2,749			2,749
Minimum pension liability adjustment, net of tax benefits of $2,701	—		—			—			(4,870	)		(4,870	)
Comprehensive income	—		—			118,217			36,225			154,442
Issuance of common stock:
Dividend reinvestment and stock purchase plan	663		28,507			—			—			28,507
Retirement savings and other plans	546		21,407			—			—			21,407
Expenses and other	—		2,215			—			—			2,215
Common stock dividends ($2.48 per share)	—		—			(89,936	)		—			(89,936	)
Balance, December 31, 2002	36,809	$	839,503		$	176,118		$	30,679		$	1,046,300

At December 31, 2002, Hawaiian Electric Industries, Inc. (HEI) had reserved a total of 8,798,249 shares of common stock for future issuance under the HEI Dividend Reinvestment and Stock Purchase Plan, the Hawaiian Electric Industries Retirement Savings Plan, the 1987 Stock Option and Incentive Plan, as amended, and other plans.

See accompanying “Notes to Consolidated Financial Statements.”

40

Consolidated Statements of Cash Flows

Hawaiian Electric Industries, Inc. and Subsidiaries

	Years ended December 31
	2002			2001			2000
	(in thousands)
Cash flows from operating activities
Income from continuing operations	$	118,217		$	107,746		$	109,336
Adjustments to reconcile income from continuing operations to net cash provided by operating activities
Depreciation of property, plant and equipment		115,597			110,425			108,608
Other amortization		25,396			19,119			10,214
Provision for loan losses		9,750			12,500			13,050
Writedowns of income notes		4,499			14,815			5,838
Deferred income taxes		35,197			382			7,142
Allowance for equity funds used during construction		(3,954	)		(4,239	)		(5,380	)
Changes in assets and liabilities, net of effects from the disposal of businesses
Decrease (increase) in accounts receivable and unbilled revenues, net		(12,203	)		23,932			(34,709	)
Increase (decrease) in accounts payable		14,566			(5,869	)		8,776
Increase (decrease) in taxes accrued		(38,419	)		(6,761	)		59,302
Changes in other assets and liabilities		(24,265	)		(12,624	)		(17,251	)
Net cash provided by operating activities		244,381			259,426			264,926
Cash flows from investing activities
Available-for-sale mortgage-related securities purchased		(1,605,672	)		(1,190,130	)		(56,567	)
Principal repayments on available-for-sale mortgage-related securities		1,182,796			605,428			55
Proceeds from sale of mortgage-related securities		77,264			701,343			—
Held-to-maturity investment securities purchased		—			—			(56,500	)
Proceeds from maturities of held-to-maturity investment securities		—			—			43,000
Proceeds from sale of investment securities		—			87,528			—
Held-to-maturity mortgage-related securities purchased		—			—			(320,102	)
Principal repayments on held-to-maturity mortgage-related securities		—			—			281,169
Loans receivable originated and purchased		(1,210,082	)		(1,036,073	)		(530,133	)
Principal repayments on loans receivable		949,262			749,378			446,647
Proceeds from sale of loans		110,465			215,888			52,328
Proceeds from sale of real estate acquired in settlement of loans		12,013			9,821			15,701
Capital expenditures		(128,082	)		(126,308	)		(134,576	)
Contributions in aid of construction		11,042			10,958			8,484
Other		(278	)		(293	)		1,270
Net cash provided by (used in) investing activities		(601,272	)		27,540			(249,224	)
Cash flows from financing activities
Net increase in deposit liabilities		121,186			94,940			92,991
Net decrease in short-term borrowings with original maturities of three months or less		—			(101,402	)		(50,431	)
Proceeds from other short-term borrowings		—			—			57,499
Repayment of other short-term borrowings		—			(3,000	)		(55,682	)
Net increase in retail repurchase agreements		12,180			6,870			8,575
Proceeds from securities sold under agreements to repurchase		1,086,531			824,692			677,677
Repayments of securities sold under agreements to repurchase		(1,116,148	)		(744,236	)		(753,525	)
Proceeds from advances from Federal Home Loan Bank		350,100			214,100			511,931
Principal payments on advances from Federal Home Loan Bank		(206,600	)		(430,600	)		(451,760	)
Proceeds from issuance of long-term debt		35,275			117,336			187,507
Repayment of long-term debt		(64,500	)		(60,500	)		(76,500	)
Preferred securities distributions of trust subsidiaries		(16,035	)		(16,035	)		(16,035	)
Net proceeds from issuance of common stock		32,451			78,937			14,080
Common stock dividends		(73,412	)		(67,015	)		(68,624	)
Other		(9,742	)		(10,659	)		(650	)
Net cash provided by (used in) financing activities		151,286			(96,572	)		77,053
Net cash provided by (used in) discontinued operations		(697	)		47,650			(77,371	)
Net increase (decrease) in cash and equivalents		(206,302	)		238,044			15,384
Cash and equivalents, January 1		450,827			212,783			197,399
Cash and equivalents, December 31	$	244,525		$	450,827		$	212,783

See accompanying “Notes to Consolidated Financial Statements.”

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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. In December 2000, HEI wrote off its indirect investment in East Asia Power Resources Corporation (EAPRC), an independent power producer in the Philippines, and in October 2001, HEI adopted a plan to exit the international power business. In November 1999, an HEI subsidiary, Hawaiian Tug & Barge Corp. (HTB), sold Young Brothers, Limited (YB) and substantially all of HTB’s operating assets. HTB’s name was changed to The Old Oahu Tug Service, Inc. (TOOTS) and it ceased operations. In September 1998, HEI adopted a plan to exit the residential real estate development business.

Basis of presentation. In preparing the consolidated financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. Actual results could differ significantly from those estimates.

Material estimates that are particularly susceptible to significant change include the amounts reported for investment securities, allowance for loan losses, regulatory assets, pension and other postretirement benefit obligations, reserves for discontinued operations, current and deferred taxes, contingencies and litigation.

Consolidation. The consolidated financial statements include the accounts of HEI and its subsidiaries (collectively, the Company). All significant intercompany accounts and transactions have been eliminated in consolidation.

Cash and equivalents. The Company considers cash on hand, deposits in banks, deposits with the Federal Home Loan Bank (FHLB) of Seattle, money market accounts, certificates of deposit, short-term commercial paper and reverse repurchase agreements and liquid investments (with original maturities of three months or less) to be cash and equivalents.

Investment securities. Debt securities that the Company intends to and has the ability to hold to maturity are classified as held-to-maturity securities and reported at amortized cost. Marketable equity securities and debt securities that are bought and held principally for the purpose of selling them in the near term are classified as trading securities and reported at fair value, with unrealized gains and losses included in earnings. Marketable equity securities and debt securities not classified as either held-to-maturity or trading securities are classified as available-for-sale securities and reported at fair value, with unrealized gains and losses excluded from earnings and reported on a net basis in a separate component of stockholders’ equity.

For securities that are not trading securities, declines in value determined to be other than temporary are included in earnings and result in a new cost basis for the investment. The specific identification method is used in determining realized gains and losses on the sales of securities.

Derivative instruments and hedging activities. Derivatives are recognized at fair value in the balance sheet as an asset or liability. Changes in fair value of derivative instruments not designated as hedging instruments are (and the ineffective portions of hedges, if any in the future, would be) recognized in earnings in the current period. In the future, any changes in the fair value of a derivative designated as a fair value hedge and the hedged item would be recorded in earnings. Also, for a derivative designated as a cash flow hedge, the effective portion of changes in fair value of the derivative would be reported in other comprehensive income and subsequently would be reclassified into earnings when the hedged item affects earnings.

Statement of Financial Accounting Standards (SFAS) No. 133, as amended, allowed the reclassification of certain debt securities from held-to-maturity to either available-for-sale or trading at the time of adoption. On January 1, 2001, approximately $2 billion in mortgage-related securities and $13 million in investment securities having estimated fair values of approximately $2 billion and $13 million, respectively, were reclassified from held-to-maturity to available-for-sale. At January 1, 2001, the net unrealized loss on securities, net of income taxes, was included in accumulated other comprehensive income within stockholders’ equity.

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Equity method. Investments in up to 50%-owned affiliates for which the Company has the ability to exercise significant influence over the operating and financing policies, are accounted for under the equity method, whereby the investment is carried at cost, plus (or minus) the Company’s equity in undistributed earnings (or losses) since acquisition. Equity in earnings or losses are reflected in operating revenues.

Property, plant and equipment. Property, plant and equipment are reported at cost. Self-constructed electric utility plant includes engineering, supervision, and administrative and general costs, and an allowance for the cost of funds used during the construction period. These costs are recorded in construction in progress and are transferred to property, plant and equipment when construction is completed and the facilities are either placed in service or become useful for public utility purposes. Upon the retirement or sale of electric utility plant, no gain or loss is recognized. The cost of the plant retired or sold and the cost of removal (net of salvage value) previously provided through depreciation are charged to accumulated depreciation.

Depreciation. Depreciation is computed primarily using the straight-line method over the estimated useful lives of the assets being depreciated. Electric utility plant has useful lives ranging from 20 to 45 years for production plant, from 25 to 50 years for transmission and distribution plant and from 8 to 45 years for general plant. The electric utility subsidiaries’ composite annual depreciation rate was 3.9% in 2002, 2001 and 2000.

Retirement benefits. Pension and other postretirement benefit costs/(returns) are charged/(credited) primarily to expense and electric utility plant. The Company’s policy is to fund pension costs in amounts consistent with the requirements of the Employee Retirement Income Security Act of 1974. Certain health care and/or life insurance benefits are provided to eligible retired employees and the employees’ beneficiaries and covered dependents.

Environmental expenditures. The Company is subject to numerous federal and state environmental statutes and regulations. In general, environmental contamination treatment costs are charged to expense, unless it is probable that the Public Utilities Commission of the State of Hawaii (PUC) would allow such costs to be recovered in future rates, in which case such costs would be capitalized as regulatory assets. Also, environmental costs are capitalized if the costs extend the life, increase the capacity, or improve the safety or efficiency of property; the costs mitigate or prevent future environmental contamination; or the costs are incurred in preparing the property for sale. Environmental costs are either capitalized or charged to expense when environmental assessments and/or remedial efforts are probable and the cost can be reasonably estimated.

Financing costs. HEI uses the effective interest method to amortize the financing costs of the holding company over the term of the related long-term debt.

Hawaiian Electric Company, Inc. (HECO) and its subsidiaries use the straight-line method to amortize financing costs and premiums or discounts over the term of the related long-term debt. Unamortized financing costs and premiums or discounts on HECO and its subsidiaries’ long-term debt retired prior to maturity are classified as regulatory assets or liabilities and are amortized on a straight-line basis over the remaining original term of the retired debt. The method and periods for amortizing financing costs, premiums and discounts, including the treatment of these items when long-term debt is retired prior to maturity, have been established by the PUC as part of the rate-making process.

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

Federal and state investment tax credits are deferred and amortized over the estimated useful lives of the properties which qualified for the credits.

Governmental tax authorities could challenge a tax return position taken by management. If the Company’s position does not prevail, the Company’s results of operations and financial condition may be adversely affected as the related deferred or current income tax asset would be impaired and written down or written off.

Earnings per share. Basic earnings per share (EPS) is computed by dividing net income by the weighted-average number of common shares outstanding for the period. Diluted EPS is computed similarly, except that common shares for dilutive stock options and dividend equivalents are added to the denominator.

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At December 31, 2002, all options to purchase common stock were included in the computation of diluted EPS. At December 31, 2001 and 2000, options to purchase 204,000 and 599,625 shares of common stock, respectively, were not included in the computation of diluted EPS because the options’ exercise prices were greater than the average market price of HEI’s common stock for 2001 and 2000, respectively, and the options were thus not dilutive.

Stock compensation. Under the 1987 Stock Option and Incentive Plan, as amended, HEI may issue an aggregate of 2,650,000 shares of common stock (1,230,190 shares unissued as of December 31, 2002) to officers and key employees as incentive stock options, nonqualified stock options, restricted stock, stock appreciation rights, stock payments or dividend equivalents. HEI has granted only nonqualified stock options and 9,000 shares of restricted stock to date. The restricted stock generally becomes unrestricted five years after the date of grant and restricted stock compensation expense has been recognized in accordance with the fair value based method of accounting in the amounts of $58,000 in 2002 and $8,000 in each of 2001 and 2000.

For the nonqualified stock options, the exercise price of each option generally equals the market price of HEI’s stock on or near the date of grant. Options generally become exercisable in installments of 25% each year for four years, and expire if not exercised ten years from the date of the grant. In general, options include dividend equivalents over the four-year vesting period and were accounted for as compensatory options under variable plan accounting in 2001 and 2000. In 2001 and 2000, the Company applied the intrinsic value-based method of accounting prescribed by Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations including Financial Accounting Standards Board (FASB) Interpretation No. 44, “Accounting for Certain Transactions involving Stock Compensation an interpretation of APB Opinion No. 25” issued in March 2000, to account for its stock options. The Company recorded stock option compensation expense of $2.6 million in 2001 and $1.9 million in 2000. For 2002, the Company applied the fair value based method of accounting prescribed by SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended, to account for its stock options. The Company recorded stock option compensation expense of $1.5 million in 2002.

In December 2002, the Company elected to adopt the recognition provisions of SFAS No. 123 as of January 1, 2002 using the “modified prospective method,” which allows recognition of stock-based employee compensation cost from the beginning of the fiscal year in which the recognition provisions are first applied as if the fair value based accounting method had been used to account for all employee awards granted, modified or settled in years since 1995.

If the accounting provisions of SFAS No. 123 had been applied to 2001 and 2000, the proforma net income and basic and diluted earnings per share would have been:

	Years ended December 31
	2002			2001			2000
	(in thousands, except per share amounts)
Net income, as reported	$	118,217		$	83,705		$	45,744
Add: Stock option expense included in reported net income, net of tax benefits		888			1,612			1,160
Deduct: Total stock option expense determined under the fair value based method, net of tax benefits		(888	)		(788	)		(747	)
Pro forma net income	$	118,217		$	84,529		$	46,157
Earnings per share
Basic—as reported	$	3.26		$	2.48		$	1.41
Basic—pro forma	$	3.26		$	2.50		$	1.42
Diluted—as reported	$	3.24		$	2.47		$	1.40
Diluted—pro forma	$	3.24		$	2.49		$	1.41

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

	2002				2001				2000
	Shares		(1)		Shares		(1)		Shares		(1)
Outstanding, January 1	814,250		$	35.58	813,625		$	35.22	739,875		$	36.21
Granted	147,000			43.36	170,000			36.29	154,000			30.10
Exercised	(328,225	)		37.07	(162,500	)		34.40	(47,500	)		34.28
Forfeited or expired	—			—	(6,875	)		37.85	(32,750	)		34.94
Outstanding, December 31	633,025		$	36.62	814,250		$	35.58	813,625		$	35.22
Options exercisable, December 31	272,775		$	34.93	447,250		$	36.24	452,125		$	36.24

(1) Weighted-average exercise price

The weighted-average fair value of each option granted during the year was $9.82, $7.92 and $9.83 (at grant date) in 2002, 2001 and 2000, respectively. The weighted-average assumptions used to estimate fair value include: risk-free interest rate of 4.6%, 4.8% and 6.3%; expected volatility of 17.5%, 18.9% and 16.5%; expected dividend yield of 7.0%, 7.0% and 6.8% for 2002, 2001 and 2000, respectively, and expected life of 4.5 years for each of the three years.

The weighted-average fair value of each option grant is estimated on the date of grant using a Binomial Option Pricing Model. At December 31, 2002, unexercised stock options have exercise prices ranging from $29.48 to $43.36 per common share, and a weighted-average remaining contractual life of 7.6 years.

Impairment of long-lived assets and long-lived asset to be disposed of. The Company reviews long-lived assets and certain identifiable intangibles for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell.

Recent accounting pronouncements and interpretations

Asset retirement obligations. In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs would be capitalized as part of the carrying amount of the long-lived asset and depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is an obligation of the electric utilities and is settled for other than the carrying amount of the liability, the electric utilities will recognize the difference as a regulatory asset or liability, as the provisions of SFAS No. 143 have no income statement impact for the electric utilities as long as the recovery of the regulatory asset or payment of the regulatory liability is probable. If the obligation is an obligation of the bank or “other” segments and is settled for other than the carrying amount of the liability, the bank and “other” segments will recognize a gain or loss on settlement. The Company adopted SFAS No. 143 on January 1, 2003 with no effect on the Company’s financial statements.

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

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May 15, 2002. The provisions of SFAS No. 145 related to SFAS No. 13 are effective for transactions occurring after May 15, 2002. All other provisions of SFAS No. 145 are effective for financial statements issued on or after May 15, 2002. Early application of the provisions of SFAS No. 145 was encouraged. The Company adopted the provisions of SFAS No. 145 in the second quarter of 2002 with no effect on the Company’s financial statements.

Costs associated with exit or disposal activities. In July 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. Examples of costs covered by the standard include lease termination costs and certain employee severance costs that are associated with a restructuring, discontinued operation, plant closing, or other exit or disposal activity. Previous accounting guidance was provided by Emerging Issues Task Force (EITF) Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” SFAS No. 146 replaces EITF Issue No. 94-3. The Company adopted the provisions of SFAS No. 146 on January 1, 2003. Since SFAS No. 146 applies prospectively to exit or disposal activities initiated after December 31, 2002, the adoption of SFAS No. 146 had no effect on the Company’s historical financial statements.

Guarantor’s accounting and disclosure requirements for guarantees. In November 2002, the FASB issued Interpretation (FIN) No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” which elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements for periods ending after December 15, 2002 about its obligations under guarantees it has issued. FIN No. 45 also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken. The Company adopted the provisions of FIN No. 45 on January 1, 2003. Since the initial recognition and measurement provisions of FIN No. 45 are applied prospectively to guarantees issued or modified after December 31, 2002, the adoption of these provisions of FIN No. 45 had no effect on the Company’s historical financial statements.

Consolidation of variable interest entities. In January 2003, the FASB issued FIN No. 46, “Consolidation of Variable Interest Entities,” which addresses the consolidation of variable interest entities (VIEs) as defined. FIN No. 46 applies immediately to variable interests in VIEs created after January 31, 2003, and to variable interests in VIEs obtained after January 31, 2003. For a variable interest in a VIE created before February 1, 2003, FIN No. 46 is applied to the enterprise no later than the beginning of the first interim or annual reporting period beginning after June 15, 2003. The application of FIN No. 46 is not expected to have a material effect on the Company’s financial statements. FIN No. 46 requires certain disclosures in financial statements issued after January 31, 2003 if it is reasonably possible that the Company will consolidate or disclose information about VIEs when FIN No. 46 becomes effective. Such disclosures are included in Note 4.

Other. For discussions of other recent accounting pronouncements, see “Stock compensation” above and “Goodwill and other intangibles” under “Bank” below.

Reclassifications. Certain reclassifications have been made to prior years’ financial statements to conform to the 2002 presentation.

Electric utility

Regulation by the PUC. The electric utility subsidiaries are regulated by the PUC and account for the effects of regulation under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” As a result, the actions of regulators can affect the timing of recognition of revenues, expenses, assets and liabilities. Management believes HECO and its subsidiaries’ operations currently satisfy the SFAS No. 71 criteria. However, if events or circumstances should change so that those criteria are no longer satisfied, management believes that a material adverse effect on the Company’s financial statements may result as regulatory assets would be charged to expense.

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Accounts receivable. Accounts receivable are recorded at the invoiced amount. The electric utility subsidiaries assess a late payment charge on balances unpaid from the previous month. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts receivable. The Company adjusts its allowance on a monthly basis, based on its historical write-off experience. Account balances are charged off against the allowance after collection efforts have been exhausted and the potential for recovery is considered remote.

Contributions in aid of construction. The electric utility subsidiaries receive contributions from customers for special construction requirements. As directed by the PUC, the subsidiaries amortize contributions on a straight-line basis over 30 years as an offset against depreciation expense.

Electric utility revenues. Electric utility revenues are based on rates authorized by the PUC and include revenues applicable to energy consumed in the accounting period but not yet billed to the customers. Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers for billing purposes is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on the following month meter readings, monthly generation volumes, estimated customer usage by account, line losses and applicable customer rates based on historical values and current rate schedules. At December 31, 2002, customer accounts receivable include unbilled energy revenues of $60 million on a base of annual revenue of $1.3 billion. Revenue amounts recorded pursuant to a PUC interim order are subject to refund, with interest, pending a final order.

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

HECO and its subsidiaries’ operating revenues include amounts for various revenue taxes they collect from customers and pay to taxing authorities. Revenue taxes to be paid to the taxing authorities are recorded as an expense and a corresponding liability in the year the related revenues are recognized. Payments to the taxing authorities are made in the subsequent year. For 2002, HECO and its subsidiaries included $111 million of revenue taxes in “operating revenues” and $113 million (including a $2 million nonrecurring PUC fee adjustment) of revenue taxes in “taxes, other than income taxes” expense. For 2001 and 2000, HECO and its subsidiaries included $114 million and $112 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

Allowance for funds used during construction (AFUDC). AFUDC is an accounting practice whereby the costs of debt and equity funds used to finance plant construction are credited on the statement of income and charged to construction in progress on the balance sheet.

The weighted-average AFUDC rate was 8.7% in 2002 and 2001 and 8.6% in 2000, and reflected quarterly compounding.

Bank

Loans receivable. American Savings Bank, F.S.B. and subsidiaries (ASB) state loans receivable at cost less an allowance for loan losses, loan origination and commitment fees and purchase premiums and discounts. Interest on loans is credited to income as it is earned. Premiums are amortized and discounts are accreted over the estimated life of the loan using the level-yield method.

Allowance for loan losses. ASB maintains an allowance for loan losses that it believes is adequate to absorb estimated losses on all loans. The level of allowance for loan losses is based on a continuing assessment of existing risks in the loan portfolio, historical loss experience, changes in collateral values, and current and anticipated economic conditions. For business and commercial real estate loans, a risk rating system is used. Loans are rated based on the degree of risk at origination and periodically thereafter, as appropriate. A credit review department performs an evaluation of these loan portfolios to ensure compliance with the internal risk rating system and timeliness of rating changes. Adverse changes in any of the risk factors could result in higher charge-offs and loan loss provisions. When loans are deemed impaired, the amount of impairment is measured based on

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the present value of expected future cash flows discounted at the loan’s effective interest rate and the fair value of the collateral securing the loan. ASB generally ceases the accrual of interest on loans when they become 90 days past due or when there is reasonable doubt as to collectibility. ASB uses either the cash or cost recovery method to record cash receipts on impaired loans that are not accruing interest. Impairment losses are charged to the provision for loan losses and included in the allowance for loan losses. For the remaining loans receivable portfolio, allowance for loan loss allocations are determined based on a loss migration analysis. The loss migration analysis determines potential loss factors based on historical loss experience for homogeneous loan portfolios.

Real estate acquired in settlement of loans. ASB records real estate acquired in settlement of loans at the lower of cost or fair value less estimated selling expenses.

Loan origination and commitment fees. ASB defers loan origination fees (net of direct costs) and recognizes such fees as an adjustment of yield over the life of the loan. ASB also defers nonrefundable commitment fees (net of direct loan origination costs, if applicable) for commitments to originate or purchase loans and, if the commitment is exercised, recognizes such fees as an adjustment of yield over the life of the loan. If the commitment expires unexercised, ASB recognizes nonrefundable commitment fees as income upon expiration.

Goodwill and other intangibles. The Company adopted the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets” on January 1, 2002. SFAS No. 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead be tested for impairment at least annually. SFAS No. 142 also requires that intangible assets with definite useful lives be amortized over their respective estimated useful lives to their estimated residual values, and be reviewed for impairment in accordance with SFAS No. 144.

Goodwill. ASB’s $83.1 million of goodwill, which is the Company’s only intangible asset with an indefinite useful life, was tested for impairment as of January 1, 2002 and will be tested for impairment annually in the fourth quarter using data as of September 30. As of January 1, 2002 and September 30, 2002, there was no impairment of goodwill. The fair value of ASB was estimated using a valuation method based on a market approach which takes into consideration market values of comparable publicly traded companies and recent transactions of companies in the industry.

In 2001 and 2000, ASB amortized goodwill on a straight-line basis over 25 years. Management evaluated whether later events or changes in circumstances indicated the remaining estimated useful life of goodwill warranted revision or that the remaining balance of goodwill was not recoverable.

Application of the provisions of SFAS No. 142 has affected the comparability of current period results of operations with prior periods because goodwill is no longer being amortized over a 25-year period. Thus, the following “transitional” disclosures present net income and earnings per common share adjusted to eliminate goodwill amortization in 2001 and 2000 as shown below.

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	Years ended December 31
	2002		2001		2000
	(in thousands, except per share amounts)
Consolidated
Reported net income	$	118,217	$	83,705	$	45,744
Goodwill amortization, net of tax benefits		—		3,845		3,816
Adjusted net income	$	118,217	$	87,550	$	49,560
Per common share:
Reported basic earnings	$	3.26	$	2.48	$	1.41
Goodwill amortization, net of tax benefits		—		0.11		0.12
Adjusted basic earnings	$	3.26	$	2.59	$	1.53
Per common share:
Reported diluted earnings	$	3.24	$	2.47	$	1.40
Goodwill amortization, net of tax benefits		—		0.11		0.12
Adjusted diluted earnings	$	3.24	$	2.58	$	1.52
Bank
Reported net income	$	56,225	$	48,531	$	40,630
Goodwill amortization, net of tax benefits		—		3,845		3,816
Adjusted net income	$	56,225	$	52,376	$	44,446

Amortized intangible assets.

	December 31
	2002				2001
	Gross carrying Amount		Accumulated amortization		Gross carrying amount	Accumulated amortization
	(in thousands)
Core deposit intangibles	$	20,276	$	11,741	20,276	$	10,010
Mortgage servicing rights		9,506		4,239	11,025		2,544
	$	29,782	$	15,980	31,301	$	12,554

	Years ended December 31
	2002		2001		2000
	(in thousands)
Aggregate amortization expense	$	3,426	$	2,981	$	2,575

The estimated aggregate amortization expense for ASB’s core deposits and mortgage servicing rights for 2003, 2004, 2005, 2006 and 2007 is $4.3 million, $3.5 million, $3.0 million, $2.6 million and $2.3 million, respectively.

Core deposit intangibles are amortized each year at the greater of the actual attrition rate of such deposit base or 10% of the original value. Core deposit intangibles are reviewed for impairment based on their estimated fair value.

ASB capitalizes mortgage servicing rights acquired through either the purchase or origination of mortgage loans for sale or securitization with servicing rights retained. Changes in mortgage interest rates impact the value of ASB’s mortgage servicing rights. Rising interest rates typically result in slower prepayment speeds in the loans being serviced for others which increases the value of mortgage servicing rights, whereas declining interest rates typically result in faster prepayment speeds which decreases the value of mortgage servicing rights and increases the amortization of the mortgage servicing rights. Currently, ASB does not hedge its mortgage servicing rights against this risk. During 2002, mortgage servicing rights acquired were not significant.

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2. Segment financial information

The electric utility and bank segments are strategic business units of the Company that offer different products and services and operate in different regulatory environments. The accounting policies of the segments are the same as those described in the summary of significant accounting policies, except that income taxes for each segment are calculated on a “stand-alone” basis. HEI evaluates segment performance based on income from continuing operations. The Company accounts for intersegment sales and transfers as if the sales and transfers were to third parties, that is, at current market prices. Intersegment revenues consist primarily of interest and preferred dividends.

Electric utility

HECO and its wholly-owned operating subsidiaries, Hawaii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (MECO), are electric public utilities in the business of generating, purchasing, transmitting, distributing and selling electric energy, and are regulated by the PUC.

Bank

ASB is a federally chartered savings bank providing a full range of banking services to individual and business customers through its branch system in Hawaii. ASB is subject to examination and comprehensive regulation by the Department of Treasury, Office of Thrift Supervision (OTS) and the Federal Deposit Insurance Corporation (FDIC), and is subject to reserve requirements established by the Board of Governors of the Federal Reserve System. By reason of the regulation of its subsidiary, ASB Realty Corporation, ASB is also subject to regulation by the Hawaii Commissioner of Financial Institutions.

Other

“Other” includes amounts for the holding companies and other subsidiaries not qualifying as reportable segments.

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	Electric Utility		Bank		Other			Total
	(in thousands)
2002
Revenues from external customers	$	1,257,171	$	399,255	$	(2,725	)	$	1,653,701
Intersegment revenues (eliminations)		5		—		(5	)		—
Revenues		1,257,176		399,255		(2,730	)		1,653,701
Depreciation and amortization		116,800		22,784		1,409			140,993
Interest expense		44,232		152,882		28,060			225,174
Profit (loss)*		146,863		87,299		(52,253	)		181,909
Income taxes (benefit)		56,658		31,074		(24,040	)		63,692
Income (loss) from continuing operations		90,205		56,225		(28,213	)		118,217
Capital expenditures		114,558		13,117		407			128,082
Assets (at December 31, 2002, including net assets of discontinued operations)		2,436,386		6,328,606		111,511			8,876,503
2001
Revenues from external customers	$	1,289,297	$	444,602	$	(6,622	)	$	1,727,277
Intersegment revenues (eliminations)		7		—		(7	)		—
Revenues		1,289,304		444,602		(6,629	)		1,727,277
Depreciation and amortization		113,455		14,444		1,645			129,544
Interest expense		47,056		213,585		31,670			292,311
Profit (loss)*		143,716		76,475		(54,288	)		165,903
Income taxes (benefit)		55,416		27,944		(25,203	)		58,157
Income (loss) from continuing operations		88,300		48,531		(29,085	)		107,746
Capital expenditures		115,540		9,827		941			126,308
Assets (at December 31, 2001, including net assets of discontinued operations)		2,389,738		6,011,448		116,757			8,517,943
2000
Revenues from external customers	$	1,277,140	$	450,878	$	4,293		$	1,732,311
Intersegment revenues (eliminations)		30		4		(34	)		—
Revenues		1,277,170		450,882		4,259			1,732,311
Depreciation and amortization		107,325		9,690		1,807			118,822
Interest expense		49,062		238,875		28,236			316,173
Profit (loss)*		142,661		64,404		(36,570	)		170,495
Income taxes (benefit)		55,375		23,774		(17,990	)		61,159
Income (loss) from continuing operations		87,286		40,630		(18,580	)		109,336
Capital expenditures		130,089		3,839		648			134,576
Assets (at December 31, 2000, including net assets of discontinued operations)		2,392,858		5,969,315		156,521			8,518,694

*    Income (loss) from continuing operations before income taxes.

Revenues attributed to foreign countries and long-lived assets located in foreign countries as of the dates and for the periods identified above were not material.

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3. Electric utility subsidiary

Selected consolidated financial information

Hawaiian Electric Company, Inc. and subsidiaries

Income statement data

	Years ended December 31
	2002			2001			2000
	(in thousands)
Revenues
Operating revenues	$	1,252,929		$	1,284,312		$	1,270,635
Other—nonregulated		4,247			4,992			6,535
		1,257,176			1,289,304			1,277,170
Expenses
Fuel oil		310,595			346,728			362,905
Purchased power		326,455			337,844			311,207
Other operation		131,910			125,565			123,779
Maintenance		66,541			61,801			66,069
Depreciation		105,424			100,714			98,517
Taxes, other than income taxes		120,118			120,894			119,784
Other—nonregulated		1,177			1,813			1,818
		1,062,220			1,095,359			1,084,079
Operating income from regulated and nonregulated activities		194,956			193,945			193,091
Allowance for equity funds used during construction		3,954			4,239			5,380
Interest and other charges		(52,822	)		(55,646	)		(57,652	)
Allowance for borrowed funds used during construction		1,855			2,258			2,922
Income before income taxes and preferred stock dividends of HECO		147,943			144,796			143,741
Income taxes		56,658			55,416			55,375
Income before preferred stock dividends of HECO		91,285			89,380			88,366
Preferred stock dividends of HECO		1,080			1,080			1,080
Net income for common stock	$	90,205		$	88,300		$	87,286

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Balance sheet data

	December 31
	2002			2001
	(in thousands)
Assets
Utility plant, at cost
Property, plant and equipment	$	3,217,016		$	3,100,297
Less accumulated depreciation		(1,367,954	)		(1,266,332	)
Construction in progress		164,300			170,558
Net utility plant		2,013,362			2,004,523
Regulatory assets		105,568			111,376
Other		317,456			273,839
	$	2,436,386		$	2,389,738
Capitalization and liabilities
Common stock equity	$	923,256		$	877,154
Cumulative preferred stock—not subject to mandatory redemption (dividend rates of 4.25-7.625%)		34,293			34,293
HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO and HECO-guaranteed debentures (distribution rates of 7.30% and 8.05%)		100,000			100,000
Long-term debt		705,270			685,269
Total capitalization		1,762,819			1,696,716
Short-term borrowings from affiliate		5,600			48,297
Deferred income taxes		158,367			145,608
Contributions in aid of construction		218,094			213,557
Other		291,506			285,560
	$	2,436,386		$	2,389,738

Regulatory assets. In accordance with SFAS No. 71, HECO and its subsidiaries’ financial statements reflect assets and costs based on current cost-based rate-making regulations. Continued accounting under SFAS No. 71 requires that certain criteria be met. Management believes HECO and its subsidiaries’ operations currently satisfy the criteria. However, if events or circumstances change so that the criteria are no longer satisfied, management believes that a material adverse effect on the Company’s financial statements may result as the regulatory assets would be charged to expense.

Regulatory assets are expected to be fully recovered through rates over PUC authorized periods ranging from one to 36 years (period noted in parenthesis) and include the following deferred costs:

	December 31
	2002		2001
	(in thousands)
Income taxes (1 to 36 years)	$	64,278	$	62,467
Postretirement benefits other than pensions (10 years)		17,897		19,687
Unamortized expense and premiums on retired debt and equity issuances (2 to 26 years)		11,005		12,100
Integrated resource planning costs (1 year)		1,965		6,243
Vacation earned, but not yet taken (1 year)		4,776		4,929
Other (1 to 4 years)		5,647		5,950
	$	105,568	$	111,376

Cumulative preferred stock. Certain cumulative preferred stock of HECO and its subsidiaries is redeemable at the option of the respective company at a premium or par, but none is subject to mandatory redemption.

Major customers. HECO and its subsidiaries received approximately 9% ($119 million), 10% ($127 million) and 10% ($123 million) of their operating revenues from the sale of electricity to various federal government agencies in 2002, 2001 and 2000, respectively.

Commitments and contingencies

Fuel contracts. HECO and its subsidiaries have contractual agreements to purchase minimum quantities of fuel oil and diesel fuel through 2004 (at prices tied to the market prices of petroleum products in Singapore and Los Angeles). Based on the average price per barrel at January 1, 2003, the estimated cost of minimum purchases under the fuel supply contracts for 2003 is $329 million. The actual cost of purchases in 2003 could vary

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substantially from this estimate as a result of changes in market prices, quantities actually purchased and/or other factors. HECO and its subsidiaries purchased $317 million, $328 million and $359 million of fuel under contractual agreements in 2002, 2001 and 2000, respectively.

Power purchase agreements. At December 31, 2002, HECO and its subsidiaries had power purchase agreements for 534 megawatts (MW) of firm capacity. The PUC allows rate recovery for energy and firm capacity payments under these agreements. Assuming that each of the agreements remains in place for its current term and the minimum availability criteria in the power purchase agreements are met, aggregate minimum fixed capacity charges are expected to be approximately $123 million each in 2003 and 2004, $118 million each in 2005, 2006 and 2007 and a total of $1.6 billion in the period from 2008 through 2030.

In general, HECO and its subsidiaries base their payments under the power purchase agreements upon available capacity and energy and they are generally not required to make payments for capacity if the contracted capacity is not available, and payments are reduced, under certain conditions, if available capacity drops below contracted levels. In general, the payment rates for capacity have been predetermined for the terms of the agreements. Energy payments will vary over the terms of the agreements. HECO and its subsidiaries pass on changes in the fuel component of the energy charges to customers through the energy cost adjustment clause in their rate schedules. HECO and its subsidiaries do not operate nor participate in the operation of any of the facilities that provide power under the agreements. Title to the facilities does not pass to HECO or its subsidiaries upon expiration of the agreements, and the agreements do not contain bargain purchase options for the facilities.

Interim increases. At December 31, 2002, HECO and its subsidiaries had recognized $16 million of revenues with respect to interim orders regarding certain integrated resource planning costs, which revenues are subject to refund, with interest, if and to the extent they exceed the amounts allowed in final orders.

HELCO power situation. In 1991, HELCO began planning to meet increased electric generation demand forecasted for 1994. HELCO’s plans were to install at its Keahole power plant two 20 MW combustion turbines (CT-4 and CT-5), followed by an 18 MW heat steam recovery generator (ST-7), at which time these units would be converted to a 56 MW (net) dual-train combined-cycle unit. In January 1994, the PUC approved expenditures for CT-4, which HELCO had planned to install in late 1994. In 1995, the PUC allowed HELCO to pursue construction of and commit expenditures for CT-5 and ST-7, but noted that such costs are not to be included in rate base until the project is installed and “is used and useful for utility purposes.” The PUC at that time also ordered HELCO to continue negotiating with independent power producers (IPPs), stating that the facility to be built should be the one that can be most expeditiously put into service at “allowable cost.”

The timing of the installation of HELCO’s phased units has been revised on several occasions due to delays in obtaining an amendment of a land use permit from the Hawaii Board of Land and Natural Resources (BLNR) and an air permit from the Department of Health of the State of Hawaii (DOH) and the U.S. Environmental Protection Agency (EPA) for the Keahole power plant site. The delays are also attributable to lawsuits, claims and petitions filed by IPPs and other parties challenging these permits and objecting to the expansion, alleging among other things that (1) operation of the expanded Keahole site would not comply with land use regulations (including noise standards) and HELCO’s land patent; (2) HELCO cannot operate the plant within current air quality standards; (3) HELCO could alternatively purchase power from IPPs to meet increased electric generation demand; and (4) HELCO’s land use entitlement expired in April 1999 because it had not completed the project within a three-year construction period.

As a result of a September 19, 2002 decision by the Third Circuit Court of the State of Hawaii (Circuit Court), relating to an extension of a construction deadline and described below under “Land use permit amendment,” the construction of CT-4 and CT-5, which had commenced in April 2002 after HELCO had obtained a final air permit and the Circuit Court had lifted a stay on construction, has been suspended. HELCO has appealed this ruling to the Hawaii Supreme Court and is considering other options that may allow HELCO to complete the installation of CT-4 and CT-5 (including seeking a land use reclassification of the Keahole site from the State Land Use Commission). If none of these options is ultimately successful, or if other permitting issues or problems arise which HELCO cannot satisfactorily resolve, HELCO may be unable to complete the installation of CT-4 and CT-5.

The following is a detailed discussion of the existing Keahole situation, including a description of its potential financial statement implications under “Management’s evaluation; costs incurred.”

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Land use permit amendment. The Circuit Court ruled in 1997 that because the BLNR had failed to render a valid decision on HELCO’s application to amend its land use permit before the statutory deadline in April 1996, HELCO was entitled to use its Keahole site for the expansion project (HELCO’s “default entitlement”). Final judgments of the Circuit Court related to this ruling are on appeal to the Hawaii Supreme Court, which in 1998 denied motions to stay the Circuit Court’s final judgment pending resolution of the appeal.

The Circuit Court’s final judgment provided that HELCO must comply with the conditions in its application and with the standard land use conditions insofar as those conditions were not inconsistent with HELCO’s default entitlement. There have been numerous proceedings before the Circuit Court and the BLNR in which certain parties (a) have sought determinations of what conditions apply to HELCO’s default entitlement, (b) have claimed that HELCO has not complied with applicable land use conditions and that its default entitlement should thus be forfeited, (c) have claimed that HELCO will not be able to operate the proposed plant without violating applicable land use conditions and provisions of Hawaii’s Air Pollution Control Act and Noise Pollution Act and (d) have sought orders enjoining any further construction at the Keahole site.

Although there has not been a final resolution of these claims, there have been several significant rulings relating to these claims, some of which may adversely affect HELCO’s ability to construct and efficiently operate CT-4 and CT-5. First, based on a change by the DOH in its interpretation of the noise rules it promulgated under the Hawaii Noise Pollution Act, the Circuit Court ruled that a stricter noise standard than the previously applied standard applies to HELCO’s plant, but left enforcement of the ruling to the DOH. HELCO filed a separate complaint for declaratory relief against the DOH seeking the invalidation of the noise rules on constitutional and other grounds. The Circuit Court denied HELCO’s motion for summary judgment, finding that the noise rules are constitutional on their face but specifically not ruling on the constitutionality of the rules as applied to Keahole. HELCO appealed the final judgment to the Hawaii Supreme Court in August 1999 and a decision on that appeal is pending. The DOH has been periodically monitoring noise levels at the site. If the DOH were to issue a notice of violation based on the stricter standards, HELCO may, among other things, assert that the noise regulations, as applied to it at Keahole, are unconstitutional. Meanwhile, while not waiving possible claims or defenses that it might have against the DOH, HELCO has installed noise mitigation measures on the existing units at Keahole and, should construction be allowed to continue, is planning to implement additional noise mitigation measures for both the existing units and for CT-4 and CT-5. The estimated cost for these additional noise mitigation measures (for the existing units and CT-4 and CT-5) is $5 million, which would be capitalized. While the noise mitigation measures were being implemented, HELCO applied to the DOH and received approval for a noise permit through 2003, which has since been extended to July 2007.

Second, in September 2000, the Circuit Court orally ruled that, absent a legal or equitable extension properly authorized by the BLNR, the three-year construction period in the standard land use conditions of the Department of Land and Natural Resources of the State of Hawaii (DLNR) expired in April 1999. On November 9, 2000, the Circuit Court issued a written ruling to that effect. In December 2000, the Circuit Court granted a motion to stay further construction until extension of the construction deadline is obtained from the BLNR. After conducting a contested case hearing in September 2001, which resulted in the hearings officer recommending an extension be granted, the BLNR, by Order dated March 25, 2002, granted HELCO an extension of the construction deadline through December 31, 2003. The extension was subject to a number of conditions, including, but not limited to, HELCO (1) complying with all applicable laws and with all conditions applicable (a) to the default entitlement, including the 15 standard land use conditions (except where deviations are approved by the BLNR), and (b) to each Conservation District Use Permit (CDUP) and amendment previously awarded to HELCO for this site; (2) agreeing to indemnify and hold the State harmless from claims arising out of any act or omission of HELCO relating to the “permit”; (3) proceeding with construction in accordance with construction plans to be submitted to and signed by the chairperson of the BLNR; (4) obtaining approval of the DOH and the Board of Water Supply for any potable water supply or sanitation facilities; (5) complying with its representations relative to mitigation, as set forth in the accepted environmental impact statement; (6) minimizing or eliminating any interference, nuisance or harm which may be caused by this land use; (7) filing, within 90 days of the Order, an application for boundary amendment with the State Land Use Commission (LUC) to remove the site from the conservation district; and (8) complying with other terms and conditions as prescribed by the chairperson of the BLNR. The Order states that failure to comply with any of these conditions would render the “permit” void. The Order also states that “no further extensions will be

55

provided.” In April 2002, based on this BLNR decision, the Circuit Court lifted the stay on construction in light of the BLNR’s Order, and construction activities on CT-4 and CT-5 then commenced.

Keahole Defense Coalition, Inc. (KDC) and two individuals appealed the BLNR’s March 25, 2002 Order to the Circuit Court, as did the Department of Hawaiian Home Lands. On September 19, 2002, the Circuit Court issued a letter to the parties indicating the Circuit Court’s decision to reverse the BLNR’s Order. The letter states that:

1. The BLNR exceeded its statutory authority in granting the extension of the permit. The findings do not support any authority by statute or rule.

2. The conclusions of law are erroneous.

3. The BLNR’s action in denying Appellants’ motion to subpoena a material witness regarding a letter issued by the DLNR on January 30, 1998 to HELCO (addressing the applicability of the standard land use conditions and stating that the three-year deadline did not apply) violated Appellants’ constitutional rights to a fair hearing.

4. The BLNR’s granting the extension is clearly erroneous in view of the BLNR’s Findings of Fact and Conclusions of Law.

The Circuit Court issued an Order to this effect on October 3, 2002.

On November 1, 2002, HELCO filed a notice of appeal of the October 3, 2002 Order (which appeal will be decided by the Hawaii Supreme Court or Hawaii Intermediate Court of Appeals). On November 15, 2002, HELCO also filed with the Hawaii Supreme Court a Motion for Stay Pending Disposition of Appeal and a Motion to Expedite Transmission of Record on Appeal. The Motion to Expedite was denied on December 10, 2002. The Motion for Stay was denied in early 2003. On November 25, 2002, KDC and two individuals filed with the Supreme Court a Motion to Dismiss this appeal on the basis that the case was moot since HELCO no longer had a default entitlement because it allegedly violated the BLNR’s March 25, 2002 Order by withdrawing its application to the LUC for a boundary amendment. That motion was denied in early 2003. Accordingly, the Hawaii Supreme Court continues to assert jurisdiction over this appeal and briefs will be filed.

On November 1, 2002, HELCO filed with the Circuit Court a notice of appeal of the original November 9, 2000 ruling that the three-year deadline had expired in April 1999. In early 2003, the Supreme Court dismissed that appeal for lack of jurisdiction. The Supreme Court’s Order stated that HELCO’s appeal was not timely filed because it was not filed within 30 days of the Circuit Court’s November 9, 2000 Order, even though the Circuit Court ruled at the time that its Order could not yet be appealed.

In the meantime, construction activities on CT-4 and CT-5 have been suspended and steps have been taken to secure the site and protect equipment and personnel.

Third, in other pending litigation, at a hearing on May 8, 2002, the Circuit Court denied the following motions made by KDC and others: a motion for a stay while one of the appeals is pending; a motion for injunction to enjoin construction (based on the allegation that HELCO’s default entitlement is no longer valid); and a motion for preliminary injunction to enjoin construction until the Hawaii Supreme Court decides HELCO’s appeal of the DOH noise regulations and until HELCO demonstrates that the expanded plant can satisfy the noise standards established in 1999 by the Circuit Court. On June 10, 2002, the nonprevailing parties filed a notice of appeal to the Hawaii Supreme Court of the Circuit Court’s decision denying the motion for injunction. The parties have filed briefs in that case.

Air permit. In 1997, the DOH issued a final air permit for the Keahole expansion project. Nine appeals of the issuance of the permit were filed with the EPA’s Environmental Appeals Board (EAB). In November 1998, the EAB denied the appeals on most of the grounds stated, but directed the DOH to reopen the permit for limited purposes. The EPA and DOH required additional data collection, which was satisfactorily completed in April 2000. A final air permit was reissued by the DOH in July 2001. Six appeals were filed with the EAB, but those appeals were denied. On November 27, 2001, the final air permit became effective.

Land Use Commission petition. One of the conditions of the construction period extension granted by the BLNR (which the Circuit Court’s October 3, 2002 Order now has reversed) was that HELCO file an application for a boundary amendment with the LUC to remove the site from the conservation district. HELCO filed the application on June 21, 2002. A hearing before the LUC was held on September 12, 2002, at which public testimony was taken

56

and memoranda were received regarding the jurisdiction of the LUC in dealing with the HELCO petition. In light of subsequent events, HELCO withdrew its petition on October 3, 2002. Under LUC rules, after such a voluntary withdrawal the applicant may submit another petition for the same property one year from the date of withdrawal. HELCO intends to submit a new petition for reclassification in the fourth quarter of 2003.

IPP Complaints. Three IPPs—Kawaihae Cogeneration Partners (KCP), Enserch Development Corporation (Enserch) and Hilo Coast Power Company (HCPC)—filed separate complaints with the PUC in 1993, 1994 and 1999, respectively, alleging that they are each entitled to a power purchase agreement (PPA) to provide HELCO with additional capacity. KCP and Enserch each claimed they would be a substitute for HELCO’s planned expansion of Keahole.

The Enserch and HCPC complaints have been resolved by HELCO’s entry into two PPAs, which were necessary to ensure reliable service to customers on the island of Hawaii, but, in the opinion of management, do not supplant the need for CT-4 and CT-5. HELCO can terminate the PPA with HCPC prior to its 2004 expiration date, for a fee.

In October 1999, the Circuit Court ruled that the lease for KCP’s proposed plant site was invalid. In January 2003, the PUC issued an order denying KCP’s July 1999 request to reopen KCP’s 1993 complaint docket and to enforce the Public Utility Regulatory Policies Act of 1978. Based on these rulings and for other reasons, management believes that KCP’s proposal for a PPA is not viable and, therefore, will not impact the need for CT-4 and CT-5.

Management’s evaluation; costs incurred. In addition to the appeal of the October 3, 2002 Circuit Court’s Order filed on November 1, 2002, HELCO is considering other options that may allow HELCO to complete the installation of CT-4 and CT-5, including seeking a land use reclassification of the Keahole site from the State Land Use Commission. At this time, the likelihood of success of any of these options cannot be ascertained. Even if the Circuit Court’s Order is ultimately overturned on appeal, however, construction is likely to be further significantly delayed, and the costs to complete construction may be significantly increased, due to the time that is likely to be required to resolve the legal proceedings. In the meantime, one concern of HELCO’s management is the condition and performance of certain aging generators on the HELCO system, which were intended to be retired or to be operated less frequently once CT-4 and CT-5 were installed, as well as the current operating status of various IPPs, which provide approximately 43% of HELCO’s generating capacity. Another concern is the possibility of power interruptions under exigent circumstances, including rolling blackouts, as IPPs and/or HELCO’s generating units become unavailable or less available (i.e., available at lower capacity) due to forced outages or planned maintenance. Such incidents occurred or were at risk of occurring on October 3, 2002 and November 8, 2002. As it has done on such occasions in the past, HELCO will endeavor to avert power interruptions, including rolling blackouts, in the future through a number of actions in addition to managing the generating units on its system, such as requesting customers to reduce demand during critical periods such as the peak evening hours. Under current system conditions, however, there can be no assurance that power interruptions will not occur.

The recovery of costs relating to CT-4 and CT-5 are subject to the rate-making process governed by the PUC. Management believes no adjustment to costs incurred to put CT-4 and CT-5 into service is required as of December 31, 2002. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HELCO may be required to write off a material portion of the costs incurred in its efforts to put these units into service whether or not CT-4 and CT-5 are installed. As of December 31, 2002, HELCO’s costs incurred in its efforts to put CT-4 and CT-5 into service and to support existing units (excluding costs the PUC permitted to be transferred to plant-in-service for pre-air permit facilities) amounted to approximately $82 million, including $32 million for equipment and material purchases, $30 million for planning, engineering, permitting, site development and other costs and $20 million for AFUDC. In addition to the $82 million in construction in progress, construction and/or purchase commitments related to CT-4 and CT-5 outstanding as of December 31, 2002 are estimated at approximately $0.6 million.

Although management believes it has acted prudently with respect to the Keahole project, effective December 1, 1998, HELCO discontinued the accrual of AFUDC on CT-4 and CT–5 due in part to the delays through that date and the potential for further delays. HELCO has also deferred plans for ST-7 to a date outside the near-term planning horizon. No costs for ST-7 are included in construction in progress.

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Oahu transmission system. Oahu’s power sources are located primarily in West Oahu. The bulk of HECO’s system load is in the Honolulu/East Oahu area. HECO transmits bulk power to the Honolulu/East Oahu area over two major transmission corridors (Northern and Southern). HECO has for some time planned to construct a part underground/part overhead 138 kilovolt (kv) transmission line from the Kamoku substation to the Pukele substation in order to close the gap between the Southern and Northern corridors and provide a third 138 kv transmission line to the Pukele substation.

Construction of the Kamoku to Pukele transmission line in its proposed location required the BLNR to approve a CDUP for the overhead portion of the line that would have been in conservation district lands. Several community and environmental groups have opposed the project, particularly the overhead portion of the line.

In November 2000, the DLNR accepted a Revised Final Environmental Impact Statement (RFEIS) prepared in support of HECO’s application for a CDUP. In January 2001, three organizations and an individual filed a complaint against the DLNR and HECO challenging the DLNR’s acceptance of the RFEIS and seeking, among other things, a judicial declaration that the RFEIS is inadequate and null and void. HECO continues to contest the lawsuit.

The BLNR held a public hearing on the CDUP in March 2001, at which several groups requested a contested case hearing which was held in November 2001. The hearings officer submitted his report, findings of fact and conclusions of law and recommended that HECO’s request for the CDUP be denied. He concluded that HECO had failed to establish that there is a need that outweighs the transmission line’s adverse impacts on conservation district lands and that there are practical alternatives that could be pursued, including an all-underground route outside the conservation district lands. On June 28, 2002, the BLNR issued a ruling denying HECO’s request for the CDUP.

HECO continues to believe that the proposed project is needed. The project would address future potential transmission line overloads in the Northern and Southern corridors under certain contingencies (in which one of the three lines feeding power to the Koolau/Pukele area served by the Northern Corridor, or to the downtown Honolulu area served by the Southern Corridor, is out for maintenance, and a second line incurs an unexpected outage), and improves the reliability of the Pukele substation. The line overload contingencies could occur, given current load growth forecasts, in 2005 for the Northern Corridor, but not until 2013 or later in the Southern Corridor. The Pukele substation, at the end of the Northern corridor, serves approximately 18% of Oahu’s electrical load, including Waikiki. If one of the 138 kV transmission lines to the Pukele substation fails while the other is out for maintenance, a major system outage would result.

HECO is evaluating alternative ways to accomplish the project, and possible future actions to expedite PUC review of the alternatives (and the need for the project). Until this evaluation of alternatives is completed, an estimated project completion date cannot be determined.

As of December 31, 2002, the accumulated costs related to the Kamoku to Pukele transmission line amounted to $17 million, including $12 million for planning, engineering and permitting costs and $5 million for AFUDC. These costs are recorded in construction in progress. The recovery of costs relating to the Kamoku to Pukele transmission line is subject to the rate-making process administered by the PUC. Management believes no adjustment to project costs incurred is required as of December 31, 2002. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HECO may be required to write off a material portion or all of the project costs incurred in its efforts to put the Kamoku to Pukele transmission line into service whether or not the project is completed.

State of Hawaii, ex rel., Bruce R. Knapp, Qui Tam Plaintiff, and Beverly Perry, on behalf of herself and all others similarly situated, Class Plaintiff, vs. The AES Corporation, AES Hawaii, Inc., HECO, and HEI. On April 22 and 23, 2002, HECO and HEI, respectively, were served with a complaint filed in the Circuit Court for the First Circuit of Hawaii which alleges that the State of Hawaii and HECO’s other customers have been overcharged for electricity as a result of alleged excessive prices in the amended power purchase agreement (Amended PPA) between defendants HECO and AES Hawaii, Inc. (AES-HI). AES-HI is a subsidiary of The AES Corporation (AES), which guarantees certain obligations of AES-HI under the Amended PPA.

HECO entered into a PPA with AES Barbers Point, Inc. (now known as AES-HI) in March 1988, and the PPA was amended in August 1989. The AES-HI 180 MW coal-fired cogeneration plant, which became operational in September 1992, utilizes a “clean-coal” technology and is designed to sell sufficient steam to be a “Qualifying Facility” under the Public Utility Regulatory Policies Act of 1978. The Amended PPA, which has a 30-year term, was

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approved by the PUC in December 1989, following contested case hearings in October 1988, an initial Decision and Order in July 1989, an amendment of the PPA in August 1989, and further contested case hearings in November 1989. Intervenors included the state Consumer Advocate and the U.S. Department of Defense. The PUC proceedings addressed a number of issues, including whether the prices for capacity and energy in the Amended PPA were less than HECO’s long-term estimated avoided costs, whether HECO needed the capacity to be provided by AES-HI, and whether the terms and conditions of the Amended PPA were reasonable.

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

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

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

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

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

As a result of the Circuit Court’s ruling, the only claim that appears to remain is under the Hawaii False Claims Act based on allegations that false bills or claims were submitted to the State after May 26, 2000. Under the False Claims Act, a defendant may be liable to a qui tam plaintiff for treble damages, plus civil penalties of a minimum of $5,000 for each false claim, plus attorneys’ fees and costs incurred in the action. The Plaintiffs appear to claim that each monthly bill submitted to each state agency and office on Oahu constitutes a separate false claim.

Management intends to vigorously defend the lawsuit.

Environmental regulation. In early 1995, the DOH initially advised HECO, HTB, YB and others that it was conducting an investigation to determine the nature and extent of actual or potential releases of hazardous substances, oil, pollutants or contaminants at or near Honolulu Harbor. The DOH issued letters in December 1995 indicating that it had identified a number of parties, including HECO, HTB and YB, who appear to be potentially responsible for the contamination and/or operated their facilities upon contaminated land. The DOH met with these identified parties in January 1996 and certain of the identified parties (including HECO, Chevron Products Company, the State of Hawaii Department of Transportation Harbors Division and others) formed a Honolulu Harbor Work Group (Work Group). Effective January 30, 1998, the Work Group and the DOH entered into a voluntary agreement and scope of work to determine the nature and extent of any contamination, the potentially responsible parties and appropriate remedial actions.

In 1999, the Work Group submitted reports to the DOH presenting environmental conditions and recommendations for additional data gathering to allow for an assessment of the need for risk-based corrective action. The Work Group also engaged a consultant who identified 27 additional potentially responsible parties (PRPs) who were not members of the Work Group, including YB. Under the terms of the 1999 agreement for

59

the sale of YB, HEI and TOOTS (formerly HTB) have specified indemnity obligations, including obligations with respect to the Honolulu Harbor investigation.

In response to the DOH’s request for technical assistance, the EPA became involved with the harbor investigation in June 2000. In November 2000, the DOH issued notices to over 20 other PRPs, including YB, regarding the ongoing investigation in the Honolulu Harbor area. A new voluntary agreement and a joint defense agreement were signed by the parties in the Work Group and some of the new PRPs, including Phillips Petroleum, but not YB. The group is now called the Iwilei District Participating Parties (Participating Parties). The Participating Parties agreed to fund remediation work using an interim cost allocation method. In September 2001, TOOTS joined the Participating Parties.

In July 2001, the EPA issued a notice of interest (Initial NOI) under the Oil Pollution Act of 1990 to HECO, YB and others regarding the Iwilei Unit of the Honolulu Harbor site. In the Initial NOI, the EPA stated that immediate subsurface investigation and assessment (also known as Rapid Assessment Work) must be conducted to delineate the extent of contamination at the site. The Participating Parties completed the Rapid Assessment Work, submitted a report to the EPA and DOH in January 2002, and developed a proposal for additional investigation (known as the Phase 2 Rapid Assessment Work), which the EPA and DOH approved. The Participating Parties substantially completed the Phase 2 Rapid Assessment Work in the third quarter of 2002 and are currently performing a data validation study of the data collected, after which they anticipate submitting a report to EPA and DOH in the second quarter of 2003.

In September 2001, the EPA and DOH concurrently issued notices of interest (collectively, the Second NOI) to the members of the Participating Parties, including HECO and TOOTS. The Second NOI identified several investigative and preliminary oil removal tasks to be taken at certain valve control facilities associated with historic pipelines in the Iwilei Unit of the Honolulu Harbor site. The Participating Parties performed the tasks identified in the Second NOI (the Phase I Pipeline Investigation) and developed a proposal for additional investigation (the Phase 2 Pipeline Investigation), which proposal the EPA and DOH approved. The Participating Parties have completed the Phase 2 Pipeline Investigation and anticipate submitting a report to the DOH and EPA in the first quarter of 2003. With the approval of the EPA and DOH, the Participating Parties also constructed a pilot Dual Phase Extraction System to remove petroleum liquids and vapors from the subsurface in a portion of the Iwilei District. Operation of the pilot extraction system began in October 2002. The pilot study supplements ongoing petroleum removal activities by the Participating Parties from wells and trenches installed as part of the investigation. The Participating Parties are currently updating the Conceptual Site Model for the Iwilei Unit, In addition, the Participating Parties plan to undertake a Feasibility Study during 2003 to identify and evaluate various remedial strategies to address petroleum products identified in the subsurface of the Iwilei District. Based on the Conceptual Site Model and the Feasibility Study, the Participating Parties will also recommend implementation of remedial strategies, where appropriate.

In October 2002, HECO and three other companies that currently have petroleum handling operations (the Operating Companies) in the Iwilei Unit entered into an agreement with the DOH to evaluate their facilities to determine whether they currently are releasing petroleum to the subsurface in the Iwilei Unit. HECO has previously investigated its facilities in the Iwilei Unit and routinely maintains them, and therefore believes that the Operating Companies evaluation will confirm that HECO’s current operations are not releasing petroleum in the Iwilei Unit.

Management has developed a preliminary estimate of costs for continuing investigative work, remedial activities and monitoring at the Iwilei Unit of the site. Management estimates that HECO will incur approximately $1.1 million (of which $0.2 million has been incurred through December 31, 2002) and TOOTS will incur approximately $0.3 million in connection with work to be performed at the site primarily from January 2002 through December 2004. These estimates were expensed in 2001. However, because (1) the full scope and extent of additional investigative work, remedial activities and monitoring are unknown at this time, (2) the final cost allocation method has not yet been determined and (3) management cannot estimate the costs to be incurred (if any) for the sites other than the Iwilei Unit (including its Honolulu power plant site), the HECO and TOOTS cost estimates may be subject to significant change and additional material investigative and remedial costs may be incurred after December 2004.

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Collective bargaining agreements. Approximately 62% of the employees of HECO, HELCO and MECO are represented by the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260 (IBEW), and are covered by collective bargaining agreements, which expire at midnight on October 31, 2003. Should the IBEW not reach agreements with HECO, HELCO and MECO upon the expiration of the existing agreements, HECO and its subsidiaries’ results of operations could be adversely affected.

4. Bank subsidiary

Selected consolidated financial information

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

Income statement data

	Years ended December 31
	2002			2001			2000
	(in thousands)
Interest and dividend income
Interest and fees on loans	$	203,082		$	231,858		$	254,502
Interest on mortgage-related securities		135,252			152,181			152,340
Interest and dividends on investment securities		7,896			15,612			16,733
		346,230			399,651			423,575
Interest expense
Interest on deposit liabilities		73,631			116,531			119,192
Interest on Federal Home Loan Bank advances		58,608			68,740			82,294
Interest on securities sold under repurchase agreements		20,643			28,314			37,389
		152,882			213,585			238,875
Net interest income		193,348			186,066			184,700
Provision for loan losses		9,750			12,500			13,050
Net interest income after provision for loan losses		183,598			173,566			171,650
Other income
Fees from other financial services		21,254			17,194			14,349
Fee income on deposit liabilities		15,734			9,401			8,760
Fee income on other financial products		10,063			8,451			3,212
Fee income on loans serviced for others, net		(164	)		2,458			2,764
Gain (loss) on sale of securities		(640	)		8,044			—
Writedown of investment		—			(6,164	)		(5,838	)
Other income		6,778			5,567			4,060
		53,025			44,951			27,307
General and administrative expenses
Compensation and employee benefits		59,594			51,932			48,423
Occupancy and equipment		30,086			28,638			27,333
Data processing		11,167			10,408			6,893
Consulting		7,693			3,825			5,449
Amortization of goodwill and core deposit intangibles		1,731			6,706			7,613
Other		33,469			34,909			33,205
		143,740			136,418			128,916
Income before minority interests and income taxes		92,883			82,099			70,041
Minority interests		173			213			225
Income taxes		31,074			27,944			23,774
Income before preferred stock dividends		61,636			53,942			46,042
Preferred stock dividends		5,411			5,411			5,412
Net income for common stock	$	56,225		$	48,531		$	40,630

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Balance sheet data

	December 31
	2002		2001
	(in thousands)
Assets
Cash and equivalents	$	214,704	$	425,595
Available-for-sale mortgage-related securities		1,952,317		1,598,100
Available-for-sale mortgage-related securities pledged for repurchase agreements		784,362		756,749
Held-to-maturity investment securities		89,545		84,211
Loans receivable, net		2,993,989		2,857,622
Other		196,117		187,217
Goodwill and other intangibles		97,572		101,954
	$	6,328,606	$	6,011,448
Liabilities and equity
Deposit liabilities–noninterest bearing	$	369,961	$	246,633
Deposit liabilities–interest bearing		3,430,811		3,432,953
Securities sold under agreements to repurchase		667,247		683,180
Advances from Federal Home Loan Bank		1,176,252		1,032,752
Other		137,888		130,494
		5,782,159		5,526,012
Minority interests and preferred stock of subsidiary		3,417		3,409
Preferred stock		75,000		75,000
Common stock		243,628		242,786
Retained earnings		192,692		165,564
Accumulated other comprehensive income (loss)		31,710		(1,323	)
		468,030		407,027
	$	6,328,606	$	6,011,448

Investment and mortgage-related securities

	December 31
	2002									2001
			Gross		Gross			Estimated				Gross		Gross			Estimated
	Amortized		unrealized		unrealized			fair		Amortized		unrealized		unrealized			fair
	cost		gains		losses			value		Cost		gains		losses			value
	(in thousands)
Available-for-sale
Mortgage-related     securities:
Private issue	$	876,561	$	8,373	$	(7,722	)	$	877,212	$	894,849	$	2,689	$	(17,961	)	$	879,577
FHLMC		539,041		7,784		(76	)		546,749		318,030		3,631		(207	)		321,454
GNMA		225,002		7,136		—			232,138		149,778		2,501		(160	)		152,119
FNMA		1,043,407		37,207		(34	)		1,080,580		990,049		14,959		(3,309	)		1,001,699
	$	2,684,011	$	60,500	$	(7,832	)	$	2,736,679	$	2,352,706	$	23,780	$	(21,637	)	$	2,354,849

As of December 31, 2002 and 2001, ASB’s held-to-maturity investment securities consisted of stock in FHLB of Seattle.

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	December 31, 2000
	Amortized cost/ carrying value		Gross unrealized gains		Gross unrealized losses			Estimated fair value
	(in thousands)
Available-for-sale
Investment securities-collateralized debt obligations	$	107,955	$	—	$	—		$	107,955
Mortgage-related securities:
FHLMC		10,477		—		(23	)		10,454
FNMA		46,037		267		(45	)		46,259
		56,514		267		(68	)		56,713
	$	164,469	$	267	$	(68	)	$	164,668
Held-to-maturity
Investment securities: Stock in FHLB of Seattle	$	78,661	$	—	$	—		$	78,661
Collateralized debt obligations		13,062		—		(262	)		12,800
		91,723		—		(262	)		91,461
Mortgage-related securities:
Private issue		1,094,723		9,243		(8,917	)		1,095,049
FHLMC		133,623		1,500		(257	)		134,866
GNMA		238,331		1,034		(475	)		238,890
FNMA		547,437		3,981		(5,050	)		546,368
		2,014,114		15,758		(14,699	)		2,015,173
	$	2,105,837	$	15,758	$	(14,961	)	$	2,106,634

ASB owns private-issue mortgage-related securities and mortgage-related securities issued by the Federal Home Loan Mortgage Corporation (FHLMC), Government National Mortgage Association (GNMA) and Federal National Mortgage Association (FNMA). Contractual maturities are not presented for mortgage-related securities because these securities are not due at a single maturity date. The weighted-average interest rate for mortgage-related securities at December 31, 2002 and 2001 was 5.62% and 6.10%, respectively.

ASB pledged mortgage-related securities with a carrying value of approximately $78 million and $108 million at December 31, 2002 and 2001, respectively, as collateral to secure public funds, deposits with the Federal Reserve Bank of San Francisco and advances from the FHLB of Seattle. At December 31, 2002 and 2001, mortgage-related securities sold under agreements to repurchase had a carrying value of $784 million and $757 million, respectively.

Pursuant to SFAS No. 133, on January 1, 2001, approximately $2 billion in mortgage-related securities and $13 million in investment securities having estimated fair values of approximately $2 billion and $13 million, respectively, were reclassified from held-to-maturity to available-for-sale. ASB did not sell held-to-maturity investment and mortgage-related securities in 2002, 2001 or 2000.

Disposition of certain debt securities. In June 2000, the OTS advised ASB that four trust certificates, in the original aggregate principal amount of $114 million, were impermissible investments under regulations applicable to federal savings banks and subsequently required ASB to dispose of the securities. The original trust certificates were purchased through two brokers and represented (i) the right to receive the principal amount of the trust certificates at maturity from an Aaa-rated swap counterparty (principal swap) and (ii) the right to receive the cash flow received on subordinated notes issued by a collateralized loan obligation (income notes or equity notes). As a result, ASB recognized interest income on these securities on a cash basis and reclassified these trust certificates from held-to-maturity status to available-for-sale status in its financial statements, recognizing a $3.8 million net loss ($5.8 million pretax) on the writedown of these securities to their then-current estimated fair value. In the first six months of 2001, ASB recognized an additional $4.0 million net loss ($6.2 million pretax) on the writedown of three of these trust certificates to their then-current estimated fair value. In April 2001, ASB sold one of the trust certificates for $30 million, an amount approximating the original purchase price.

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After ASB demanded that PaineWebber Incorporated (the broker through whom the remaining three trust certificates were purchased) rescind the transactions, ASB filed a lawsuit against PaineWebber Incorporated. ASB is seeking rescission or other remedies, including recovery of any losses ASB (directly and through its indemnification of HEI) may incur as a result of its purchase and ownership of these trust certificates.

To bring ASB into compliance with the OTS direction, ASB directed the trustees to terminate the principal swap component of the three trust certificates and received $43 million from the swaps. Prior to terminating the swaps, ASB had received $2 million of cash from the three trust certificates. After terminating the swaps, the related equity notes were sold by the swap counterparty to HEI. In May 2001, HEI purchased two series of the income notes for approximately $21 million and, in July 2001, HEI purchased the third series of income notes for approximately $7 million. As of December 31, 2002, HEI had received $9.1 million of cash from these income notes. The three series of income notes purchased by HEI represent residual equity interests in three entities (Avalon CLO, Pilgrim 1999-01 CLO, and Avalon CLO II) which, as of December 31, 2002, held cash and collateralized corporate debt securities having an estimated par value of approximately $1.7 billion. The entities manage the portfolio of collateralized debt securities, pay expenses and make payments to the various class note holders as specified in the various note agreements. HEI is not the primary beneficiary of these entities, and HEI’s maximum pre-tax exposure to additional loss as a result of its ownership of the income notes is $7 million as of December 31, 2002.

Due to the uncertainty of future cash flows, HEI is accounting for the income notes under the cost recovery method of accounting. In the second half of 2001 and in 2002, HEI recognized a $5.6 million ($8.7 million pretax) and a $2.9 million ($4.5 million pretax), respectively, net loss on the writedown of the three income notes to their then-current estimated fair value based upon an independent third party valuation that is updated quarterly. As of December 31, 2002, the estimated fair value and carrying value (including valuation adjustments) of the income notes totaled approximately $8.0 million. HEI could incur additional losses from the ultimate disposition of these income notes due to further “other-than-temporary” declines in their fair value. ASB has agreed to indemnify HEI against losses related to these income notes, but the indemnity obligation is payable solely out of any recoveries achieved in the litigation against PaineWebber Incorporated. In 2002, PaineWebber Incorporated filed a counterclaim alleging misrepresentation and fraud among other allegations. In January 2003, a hearing on several motions for partial summary judgment was held. The Court denied all motions, except for a ruling that PaineWebber did not owe a fiduciary duty to ASB with respect to two of the three transactions. The Company has filed a motion for reconsideration on this ruling. All other claims and issues were reserved for the trial, which is scheduled to begin in July 2003. Additional discovery and pretrial motion work is anticipated prior to trial. The ultimate outcome of this litigation cannot be determined at this time.

Loans receivable

	December 31
	2002			2001
	(in thousands)
Real estate loans
One-to-four unit residential and commercial	$	2,526,505		$	2,408,177
Construction and development		46,150			52,043
		2,572,655			2,460,220
Loans secured by savings deposits		8,034			7,288
Consumer loans		237,819			245,199
Commercial loans		247,114			197,333
		3,065,622			2,910,040
Undisbursed portion of loans in process		(21,413	)		(22,915	)
Deferred fees and discounts, including net purchase accounting discounts		(19,180	)		(17,946	)
Allowance for loan losses		(45,435	)		(42,224	)
Loans held to maturity		2,979,594			2,826,955
Residential loans held for sale		14,395			29,248
Commercial real estate loans held for sale		—			1,419
	$	2,993,989		$	2,857,622

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At December 31, 2002 and 2001, the weighted-average interest rate for loans receivable was 6.52% and 7.25%, respectively.

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

At December 31, 2002 and 2001, the aggregate amount of loans to directors and executive officers of ASB and its affiliates and any related interests (as defined in Federal Reserve Board Regulation O) of such individuals, was $61 million and $19 million, respectively. Of the $42 million increase in such loans in 2002, $25 million were primarily attributed to existing loans of a new ASB director’s related interest and $17 million related to new loans made to related interests of directors of ASB. At December 31, 2002 and 2001, $50 million and $10 million of the loan balances, respectively, were to related interests of individuals who are directors of ASB. All such loans were made at ASB’s normal credit terms except that residential real estate loans and consumer loans to directors and executive officers of ASB were made at preferred employee interest rates. In ASB’s opinion, these loans do not represent more than a normal risk of collection.

At December 31, 2002, ASB had impaired loans totaling $22.2 million, which consisted of $10.7 million of income property loans and $11.5 million of commercial loans. At December 31, 2001, ASB had impaired loans totaling $20.3 million, which consisted of $14.6 million of income property loans, $0.2 million of residential real estate loans for properties of one-to-four units and $5.5 million of commercial loans. The average balances of impaired loans during 2002, 2001 and 2000 were $26.0 million, $23.2 million and $36.0 million, respectively. At December 31, 2002, 2001 and 2000, the allowance for loan losses for impaired loans was $0.3 million, $3.7 million and $4.8 million, respectively.

At December 31, 2002 and 2001, ASB had nonaccrual and renegotiated loans of $26 million and $44 million, respectively.

ASB realized $0.4 million, $1.5 million and $1.9 million of interest income on nonaccrual loans in 2002, 2001 and 2000, respectively. If these loans would have earned interest in accordance with their original contractual terms ASB would have realized $0.9 million, $2.2 million and $2.8 million in 2002, 2001 and 2000, respectively.

ASB services real estate loans owned by third parties ($0.9 billion, $1.1 billion and $0.6 billion at December 31, 2002, 2001 and 2000, respectively), which are not included in the accompanying consolidated financial statements. ASB reports fees earned for servicing loans as income when the related mortgage loan payments are collected and charges loan servicing costs to expense as incurred.

At December 31, 2002 and 2001, commitments not reflected in the consolidated balance sheets consisted of: commitments to originate loans, other than loans in process, of $69.4 million and $40.8 million, respectively; standby, commercial and banker’s acceptance letters of credit of $11.2 million and $9.6 million, respectively; and unused lines of credit of $690.3 million and $652.8 million, respectively.

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

	Years ended December 31,
	2002			2001			2000
	(dollars in thousands)
Allowance for loan losses, January 1	$	42,224		$	37,449		$	35,348
Provision for loan losses		9,750			12,500			13,050
Net charge-offs
Real estate loans		1,876			3,414			6,727
Other loans		4,663			4,311			4,222
Total net charge-offs		6,539			7,725			10,949
Allowance for loan losses, December 31	$	45,435		$	42,224		$	37,449
Ratio of allowance for loan losses, December 31, to average loans outstanding		1.60	%		1.42	%		1.16	%
Ratio of provision for loan losses during the year to average loans outstanding		0.34	%		0.42	%		0.41	%
Ratio of net charge-offs during the year to average loans outstanding		0.23	%		0.26	%		0.34	%

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Real estate acquired in settlement of loans. At December 31, 2002 and 2001, ASB’s real estate acquired in settlement of loans was $12.1 million and $14.5 million, respectively.

Deposit liabilities

	December 31
	2002				2001
	Weighted- average stated rate		Amount		Weighted- average stated rate		Amount
	(in thousands)
Commercial checking	—	%	$	241,996	—	%	$	144,885
Other checking	0.13			620,631	0.21			625,248
Passbook	0.75			1,226,337	1.50			1,104,725
Money market	1.04			442,735	1.79			337,997
Term certificates	3.80			1,269,073	4.43			1,466,731
	1.65	%	$	3,800,772	2.42	%	$	3,679,586

At December 31, 2002 and 2001, deposit accounts of $100,000 or more totaled $0.8 billion and $0.7 billion, respectively.

The approximate amounts of term certificates outstanding at December 31, 2002 with scheduled maturities for 2003 through 2007 were $505.7 million in 2003, $291.7 million in 2004, $301.7 million in 2005, $63.5 million in 2006 and $55.2 million in 2007.

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

	Years ended December 31
	2002		2001		2000
	(in thousands)
Interest-bearing checking	$	1,059	$	4,150	$	5,484
Passbook		14,512		20,004		21,186
Money market		6,092		7,432		9,015
Term certificates		51,968		84,945		83,507
	$	73,631	$	116,531	$	119,192

Securities sold under agreements to repurchase

	December 31, 2002
Maturity	Repurchase liability		Weighted-average interest rate		Collateralized by mortgage-related securities–fair value plus accrued interest
	(in thousands)
Overnight	$	34,845	1.15	%	$	42,072
1 to 29 days		60,077	1.39			71,680
30 to 90 days		116,599	2.23			128,343
Over 90 days		455,726	3.80			546,122
	$	667,247	3.17	%	$	788,217

        At December 31, 2002, securities sold under agreements to repurchase consisted of mortgage-related securities sold under fixed-coupon agreements. The FHLMC, GNMA and FNMA mortgage-related securities are book-entry securities and were delivered by appropriate entry into the counterparties’ accounts at the Federal Reserve System. The remaining securities underlying the agreements were delivered to the brokers/dealers who arranged the transactions. The carrying value of securities underlying the agreements remained in ASB’s asset accounts and the obligation to repurchase securities sold is reflected as a liability in the consolidated balance sheet. At December 31, 2002 and 2001, ASB had agreements to repurchase identical securities totaling $667 million and $683 million, respectively. At December 31, 2002 and 2001, the weighted-average rate on securities sold under agreements to repurchase was 3.17% and 2.81%, respectively, and the weighted-average remaining days to maturity was 454 days and 114 days, respectively. During 2002, 2001 and 2000, securities sold under agreements

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to repurchase averaged $663 million, $629 million and $625 million, respectively, and the maximum amount outstanding at any month-end was $751 million, $722 million and $657 million, respectively.

Advances from Federal Home Loan Bank

	December 31
	2002				2001
	Weighted- average stated rate		Amount		Weighted- average stated rate		Amount
	(in thousands)
Due in
2002	NA			NA	3.91	%	$	172,800
2003	4.58	%	$	272,700	4.96			252,700
2004	4.95			329,321	5.36			264,321
2005	5.98			382,231	6.48			308,931
2006	6.70			36,000	6.93			34,000
2007	3.81			156,000	—			—
	5.10	%	$	1,176,252	5.41	%	$	1,032,752

NA Not applicable.

Advances from the FHLB of Seattle are secured by mortgage-related securities, loans and stock in the FHLB of Seattle. As a member of the FHLB system, ASB is required to own a specific number of shares of capital stock of the FHLB of Seattle.

Common stock equity. As of December 31, 2002, ASB was in compliance with the minimum capital requirements under OTS regulations. HEI agreed with the OTS predecessor regulatory agency that it would contribute additional capital to ASB up to a maximum aggregate amount of approximately $65 million. As of December 31, 2002, HEI’s maximum obligation to contribute additional capital has been reduced to approximately $28 million.

5.  Short-term borrowings

No commercial paper was outstanding at December 31, 2002 and 2001.

At December 31, 2002 and 2001, HEI maintained bank lines of credit which totaled $70 million ($30 million maturing in April 2003, $30 million in June 2003 and $10 million in October 2003) and $70 million, respectively, and HECO maintained bank lines of credit which totaled $100 million ($20 million maturing in March 2003, $30 million in April 2003, $10 million in May 2003 and $40 million in June 2003) and $110 million, respectively. On January 1, 2003, HECO reduced its total lines of credit to $90 million, thereby reducing to $30 million the HECO lines maturing in June 2003. HEI and HECO maintain lines of credit to support the issuance of commercial paper and for other general corporate purposes. None of the lines are secured. HECO borrowed and repaid $8.8 million under a line of credit in 2001. There were no borrowings under any line of credit at December 31, 2001 or during 2002.

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6. Long-term debt

	December 31
	2002			2001
	(in thousands)
HELCO first mortgage bonds—7.75-7.88%, paid in 2002	$	—		$	5,000
Obligations to the State of Hawaii for the repayment of special purpose revenue bonds issued on behalf of electric utility subsidiaries
4.95%, due 2012		57,500			57,500
5.45-7.60%, due 2020-2023		240,000			240,000
5.65-6.60%, due 2025-2027		272,000			272,000
5.50-6.20%, due 2014-2029		116,400			116,400
5.10%, due 2032		40,000			—
		725,900			685,900
Less funds on deposit with trustees		(16,111	)		(10,808	)
Less unamortized discount		(4,519	)		(4,418	)
		705,270			670,674
Promissory notes
Variable rate (5.54% at December 31, 2002), due in 2003		100,000			100,000
7.9% note, paid in 2002		—			9,595
6.15-7.56%, due in various years through 2014		301,000			360,500
		401,000			470,095
	$	1,106,270		$	1,145,769

At December 31, 2002, the aggregate principal payments required on long-term debt for 2003 through 2007 are $136 million in 2003, $1 million in 2004, $37 million in 2005, $110 million in 2006 and $10 million in 2007.

In January 2003, MECO’s proportionate share of the 6.55% Series 1992 Special Purpose Revenue Bonds, in the principal amount of $8.0 million, was called for redemption on March 12, 2003.

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

	December 31
	2002		2001		Liquidation value per security
	(in thousands, except per security amounts and number of securities)
Hawaiian Electric Industries Capital Trust I* 8.36% Trust Originated Preferred Securities (4,000,000 securities)**	$	100,000	$	100,000	$	25
HECO Capital Trust I* 8.05% Cumulative Quarterly Income Preferred Securities, Series 1997 (2,000,000 securities)***		50,000		50,000		25
HECO Capital Trust II* 7.30% Cumulative Quarterly Income Preferred Securities, Series 1998 (2,000,000 securities)****		50,000		50,000		25
	$	200,000	$	200,000

* Delaware grantor trust.

** No scheduled maturity. Redeemable at the issuer’s option after February 4, 2002.

*** Mandatorily redeemable at the maturity of the underlying debt on March 27, 2027, which maturity may be extended to no later than March 27, 2046. Also, redeemable at the issuer’s option after March 27, 2002.

**** Mandatorily redeemable at the maturity of the underlying debt on December 15, 2028, which maturity may be extended to no later than December 15, 2047. Also, redeemable at the issuer’s option after December 15, 2003.

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8. Retirement benefits

Pensions. Substantially all of the employees of HEI and the utility subsidiaries participate in the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries and substantially all of the employees of ASB and its subsidiaries participate in the American Savings Bank Retirement Plan (collectively, Plans). The Plans are qualified, non-contributory defined benefit pension plans with the benefits for union employees determined in accordance with the terms of the collective bargaining agreements between the utilities and their respective unions. The Plans are subject to the provisions of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In addition, some current and former executives and directors of HEI and its subsidiaries participate in noncontributory, nonqualified plans (collectively, Supplemental/Excess/Directors Plans). In general, benefits are based on the employees’ years of service and compensation.

The Plans and the Supplemental/Excess/Directors Plans were adopted with the expectation that they will continue indefinitely, but the continuation of these plans and the payment of any contribution thereunder is not assumed as a contractual obligation by the participating employers. Each participating employer reserves the right to terminate its participation in the applicable plan at any time, and HEI and ASB reserve the right to terminate their respective plan at any time. If a participating employer terminated its participation in the Plans, the interest of each affected participant would become 100% vested to the extent funded. Upon the termination of the Plans, assets would be distributed to affected participants in accordance with the applicable allocation provisions of ERISA and any excess assets that exist would be paid to the Participating Employers. Participants’ benefits are covered up to certain limits under insurance provided by the Pension Benefit Guaranty Corporation (PBGC).

The Participating Employers contribute amounts to a master pension trust (Trust) for the Plans in accordance with the funding requirements of ERISA and considering the deductibility of contributions under the Internal Revenue Code (Code). The funding of the Plans is based on actuarial assumptions adopted by the Pension Investment Committee administering the Plans on the advice of an enrolled actuary.

To determine pension costs for HEI and its subsidiaries under the Plans and the Supplemental/Excess/Directors Plans, it is necessary to make complex calculations and estimates based on numerous assumptions, including the weighted-average assumptions identified below.

Postretirement benefits other than pensions. HEI and the electric utility subsidiaries provide eligible employees health and life insurance benefits upon retirement under the Postretirement Welfare Benefits Plan for Employees of Hawaiian Electric Company, Inc. and Participating Employers. The amount of health benefits is based on retirees’ years of service and retirement date. Generally, employees are eligible for these benefits if, upon retirement, they participate in the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries.

The postretirement benefits plan was adopted with the expectation that it will continue indefinitely, but the continuation of the plan and the payment of any contribution thereunder is not assumed as a contractual obligation by the participating employers. Each participating employer reserves the right to terminate its participation in the postretirement benefits plan at any time.

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Pension and other postretirement benefit plans information. The changes in the pension and other postretirement benefit defined benefit plans’ obligations and plan assets, the funded status of the plans and the unrecognized and recognized amounts reflected in the balance sheet were as follows:

	Pension benefits						Other benefits
	2002			2001			2002			2001
	(in thousands)
Benefit obligation, January 1	$	646,197		$	599,669		$	146,486		$	124,924
Service cost		20,215			19,390			3,135			3,051
Interest cost		45,806			43,512			10,158			9,348
Amendments		(34	)		247			—			222
Actuarial loss		52,597			17,475			6,051			15,576
Benefits paid		(36,001	)		(34,096	)		(6,400	)		(6,635	)
Benefit obligation, December 31		728,780			646,197			159,430			146,486
Fair value of plan assets, January 1		719,112			836,910			90,041			104,099
Actual loss on plan assets		(97,541	)		(84,274	)		(14,169	)		(11,457	)
Employer contribution		3,522			572			6,454			4,034
Benefits paid		(36,001	)		(34,096	)		(6,400	)		(6,635	)
Fair value of plan assets, December 31		589,092			719,112			75,926			90,041
Funded status		(139,688	)		72,915			(83,504	)		(56,445	)
Unrecognized net actuarial loss (gain)		209,828			(24,756	)		24,361			(6,599	)
Unrecognized net transition obligation		981			3,251			32,781			36,059
Unrecognized prior service cost (gain)		(6,999	)		(7,470	)		196			209
Net amount recognized, December 31	$	64,122		$	43,940		$	(26,166	)	$	(26,776	)
Amounts recognized in the balance sheet consist of:
Prepaid benefit cost	$	70,328		$	51,894		$	—		$	—
Accrued benefit liability		(15,063	)		(9,313	)		(26,166	)		(26,776	)
Intangible asset		690			7			—			—
Accumulated other comprehensive income		8,167			1,352			—			—
Net amount recognized, December 31	$	64,122		$	43,940		$	(26,166	)	$	(26,776	)

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

	December 31
	Pension benefits						Other benefits
	2002		2001		2000		2002		2001		2000
Discount rate	6.75	%	7.25	%	7.50	%	6.75	%	7.25	%	7.50	%
Expected return on plan assets	9.0		10.0		10.0		9.0		10.0		10.0
Rate of compensation increase	4.6		4.6		4.6		4.6		4.6		4.6

At December 31, 2002, the assumed health care trend rates for 2003 and future years were as follows: medical, 9.28%, grading down to 4.25%; dental, 4.25%; and vision, 3.25%. At December 31, 2001, the assumed health care trend rates for 2002 and future years were as follows: medical, 10.00%, grading down to 4.75%; dental, 4.75%; and vision, 3.75%.

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

	Years ended December 31
	Pension benefits									Other benefits
	2002			2001			2000			2002			2001			2000
	(in thousands)
Service cost	$	20,215		$	19,390		$	18,254		$	3,135		$	3,051		$	2,832
Interest cost		45,806			43,512			41,656			10,158			9,348			8,938
Expected return on plan assets		(80,958	)		(80,281	)		(74,708	)		(10,023	)		(10,032	)		(9,327	)
Amortization of unrecognized transition obligation		2,270			2,326			2,326			3,278			3,278			3,278
Amortization of prior service cost (gain)		(505	)		(482	)		(413	)		13			13			–
Recognized actuarial gain		(3,489	)		(8,183	)		(9,438	)		(716	)		(2,599	)		(3,113	)
Net periodic benefit cost (return)	$	(16,661	)	$	(23,718	)	$	(22,323	)	$	5,845		$	3,059		$	2,608

Of the net periodic pension benefit costs (returns), the Company recorded income of $11 million in 2002, $17 million in 2001 and 2000, and credited the remaining amounts primarily to electric utility plant. Of the net periodic other benefit costs, the Company expensed $4 million, $2 million and $2 million in 2002, 2001 and 2000, respectively, and charged the remaining amounts primarily to electric utility plant.

The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for pension plans with an accumulated benefit obligation in excess of plan assets were $55 million, $42 million and $29 million, respectively, as of December 31, 2002 and $9 million, $8 million and nil, respectively, as of December 31, 2001.

The health care cost trend rate assumptions can have a significant effect on the amounts reported for other benefits. At December 31, 2002, a one-percentage-point increase in the assumed health care cost trend rates would have increased the total service and interest cost by $0.3 million and the postretirement benefit obligation by $3.8 million, and a one-percentage-point decrease would have reduced the total service and interest cost by $0.3 million and the postretirement benefit obligation by $4.5 million.

9. Income taxes

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

	Years ended December 31
	2002			2001			2000
	(in thousands)
Federal
Current	$	24,791		$	56,648		$	51,702
Deferred		35,614			(730	)		6,230
Deferred tax credits, net		(1,557	)		(1,567	)		(1,585	)
		58,848			54,351			56,347
State
Current		2,668			248			2,968
Deferred		1,139			1,112			912
Deferred tax credits, net		1,037			2,446			932
		4,844			3,806			4,812
	$	63,692		$	58,157		$	61,159

        In March 1998, ASB formed a subsidiary, ASB Realty Corporation, which elects to be taxed as a real estate investment trust. This reorganization has reduced Hawaii bank franchise taxes, net of federal income taxes, of HEI Diversified, Inc. (HEIDI) and ASB by $17 million for 2002 and prior years. ASB has taken a dividends received deduction on dividends paid to it by ASB Realty Corporation in the returns filed in 1999 through 2002. The State of Hawaii Department of Taxation has challenged ASB’s position and has issued notices of tax assessment for 1999, 2000 and 2001. The aggregate amount of tax assessments is approximately $14 million (or $9 million, net of income tax benefits) for tax years 1999 through 2001, plus interest of $3 million (or $2 million, net of income tax benefits) through December 31, 2002. The interest on the tax is accruing at a simple interest rate of 8%. Although

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not yet assessed, the potential bank franchise tax liability for 2002 if ASB’s tax position does not prevail is $6 million (or $4 million, net of income tax benefits), plus interest of $0.3 million through December 31, 2002. ASB believes that its tax position is proper and, in October 2002, filed an appeal with the State Board of Review, First Taxation District. No provision for Hawaii bank franchise taxes has been made since 1998.

A reconciliation of the amount of income taxes computed at the federal statutory rate of 35% to the amount provided in the Company’s consolidated statements of income was as follows:

	Years ended December 31
	2002			2001			2000
	(in thousands)
Amount at the federal statutory income tax rate	$	63,668		$	58,066		$	59,673
Increase (decrease) resulting from:
State income taxes, net of effect on federal income taxes		3,149			2,474			3,129
Preferred stock dividends of subsidiaries		698			698			698
Other, net		(3,823	)		(3,081	)		(2,341	)
	$	63,692		$	58,157		$	61,159

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

	December 31
	2002		2001
	(in thousands)
Deferred tax assets
Property, plant and equipment	$	12,894	$	13,654
Contributions in aid of construction and customer advances		46,052		47,546
Allowance for loan losses		15,783		17,740
Other		29,963		29,222
		104,692		108,162
Deferred tax liabilities
Property, plant and equipment		174,924		170,561
Leveraged leases		35,796		38,398
Real estate investment trust dividends (federal income taxes only)		28,409		–
Net unrealized gains on available-for-sale mortgage-related securities		16,888		3,467
Regulatory assets		24,794		24,313
FHLB stock dividend		16,547		16,458
Other		42,765		40,401
		340,123		293,598
Net deferred income tax liability	$	235,431	$	185,436

The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Based upon historical taxable income, projections for future taxable income and available tax planning strategies, management believes it is more likely than not the Company will realize the benefits of the deferred tax assets and has provided no valuation allowance for deferred tax assets during 2002, 2001 and 2000.

10 • Cash flows

Supplemental disclosures of cash flow information. In 2002, 2001 and 2000, the Company paid interest amounting to $225 million, $293 million and $309 million, respectively.

In 2002, 2001 and 2000, the Company paid income taxes amounting to $60 million, $30 million and $11 million, respectively.

Supplemental disclosures of noncash activities. In April 2000, HEI recommenced issuing new common shares under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP). From March 1998 to March 2000, HEI had acquired for cash its common shares in the open market to satisfy the requirements of the HEI DRIP. Under the

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HEI DRIP, common stock dividends reinvested by shareholders in HEI common stock in noncash transactions amounted to $17 million in 2002, $16 million in 2001 and $12 million in 2000.

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

In 2002, 2001 and 2000, HECO and its subsidiaries capitalized as part of the cost of electric utility plant an allowance for equity funds used during construction amounting to $4 million, $4 million and $5 million, respectively.

The estimated fair value of noncash contributions in aid of construction amounted to $4 million, $2 million and $7 million in 2002, 2001 and 2000, respectively.

In 2002, HECO assigned account receivables totaling $10 million to a creditor, without recourse, in full settlement of HECO’s $10 million notes payable to that creditor.

11. Regulatory restrictions on net assets

At December 31, 2002, HECO and its subsidiaries could not transfer approximately $452 million of net assets to HEI in the form of dividends, loans or advances without regulatory approval.

ASB is required to file a notice with the OTS 30 days prior to making any capital distribution to HEI. Generally, the OTS may disapprove or deny ASB’s notice of intention to make a capital distribution if the proposed distribution will cause ASB to become undercapitalized, or the proposed distribution raises safety and soundness concerns, or the proposed distribution violates a prohibition contained in any statue, regulation, or agreement between ASB and the OTS. At December 31, 2002, ASB could transfer approximately $104 million of net assets to HEI in the form of dividends and still maintain its “well-capitalized” position.

HEI management expects that the regulatory restrictions will not materially affect the operations of the Company nor HEI’s ability to pay common stock dividends.

12. Significant group concentrations of credit risk

Most of the Company’s business activity is with customers located in the State of Hawaii. Most of ASB’s financial instruments are based in the State of Hawaii, except for the mortgage-related securities it owns. Substantially all real estate loans receivable are secured by real estate in Hawaii. ASB’s policy is to require mortgage insurance on all real estate loans with a loan to appraisal ratio in excess of 80% at origination. At December 31, 2002, ASB’s private-issue mortgage-related securities represented whole or participating interests in pools of mortgage loans collateralized by real estate in the continental U.S. As of December 31, 2002, various securities rating agencies rated the private-issue mortgage-related securities held by ASB as investment grade.

13. Discontinued operations

HEI Power Corp. (HEIPC). On October 23, 2001, the HEI Board of Directors adopted a formal plan to exit the international power business (engaged in by HEIPC and its subsidiaries, the HEIPC Group). HEIPC management has been carrying out a program to dispose of all of the HEIPC Group’s remaining projects and investments. Accordingly, the HEIPC Group has been reported as a discontinued operation in the Company’s consolidated statements of income.

Guam project. In September 1996, HEI Power Corp. Guam (HPG) entered into an energy conversion agreement for approximately 20 years with the Guam Power Authority, pursuant to which HPG repaired and operated two oil-fired 25 MW (net) units in Tanguisson, Guam. In November 2001, HEI sold HPG for a nominal gain. In the stock purchase agreement, HEIPC agreed to indemnify the purchaser of HPG with respect to representations, warranties and covenants made by HEIPC (e.g., that the project and project site suffered from no environmental liabilities except as disclosed and that HEIPC would bear the risk that the final provisions of a required air permit would be more onerous than the preliminary draft provided at closing). No amounts have been accrued related to the indemnities and the maximum potential exposure is estimated to be the sales price of $13 million.

China project. In 1998 and 1999, the HEIPC Group acquired what became a 75% interest in a joint venture, Baotou Tianjiao Power Co., Ltd., formed to construct, own and operate a 200 MW (net) coal-fired power plant to be located in Inner Mongolia. The power plant was intended to be built “inside the fence” for Baotou Iron & Steel (Group) Co., Ltd. The project received approval from both the national and Inner Mongolia governments. However, the Inner Mongolia Power Company, which owns and operates the electricity grid in Inner Mongolia, caused a delay

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of the project by failing to enter into a satisfactory interconnection arrangement with the joint venture. The Inner Mongolia Power Company was seeking to limit the joint venture’s load, which is inconsistent with the terms of the project approvals and the power purchase contract. Upon appeal to the Inner Mongolia government, the Inner Mongolia Economic and Trade Committee (the regulator of the electric utility industry) refused to enforce the HEIPC Group’s rights associated with the approved project. The HEIPC Group determined that a satisfactory interconnection arrangement could not be obtained and is not proceeding with the project. (An indirect subsidiary of HEIPC has a conditional, nonrecourse commitment to make an additional investment in Baotou Tianjiao Power Co., Ltd., but it is HEIPC’s position that the conditions to this commitment have not been satisfied and no further investment will be made.) In the third quarter of 2001, the HEIPC Group wrote off its remaining investment of approximately $24 million in the project. The HEIPC Group is continuing to pursue recovery of the costs incurred in connection with the joint venture interest; however, there can be no assurance that any amount will be recovered and no recovery has been accrued on the financial statements of the Company.

Philippines investments. In March 2000, the HEIPC Group acquired a 50% interest in EPHE Philippines Energy Company, Inc. (EPHE), an indirect subsidiary of El Paso Corporation, for $87.5 million. EPHE then owned approximately 91.7% of the common shares of East Asia Power Resources Corporation (EAPRC), a Philippines holding company primarily engaged in the electric generation business in Manila and Cebu through its subsidiaries.

Due to the equity losses of $24.1 million incurred in 2000 from the investment in EPHE and the changes in the political and economic conditions related to the investment (primarily devaluation of the Philippine peso and increase in fuel oil prices), management determined that the investment in EAPRC was impaired and, on December 31, 2000, wrote off the remaining $65.7 million investment in EAPRC. Also, on December 31, 2000, HEI accrued a potential payment obligation under an HEI guaranty of $10 million of EAPRC loans. In the first quarter of 2001, HEI was partially released ($1.5 million) from the guaranty obligation; and, in August 2002, HEI paid approximately $8.5 million in full satisfaction of such obligation. The indirect subsidiary of HEIPC which held the shares in EPHE has been dissolved and those shares were cancelled by a reduction of the capital stock of EPHE approved by the Philippine Securities and Exchange Commission.

In December 1998, the HEIPC Group invested $7.6 million to acquire convertible preferred shares in Cagayan Electric Power & Light Co., Inc. (CEPALCO), an electric distribution company in the Philippines. In September 1999, the HEIPC Group also acquired 5% of the outstanding CEPALCO common stock for $2.1 million. In July 2001, the preferred shares were converted to common stock. The HEIPC Group currently owns approximately 22% of the outstanding common stock of CEPALCO. This investment is classified as available for sale. The HEIPC Group recognized an impairment loss of approximately $2.7 million in the third quarter of 2001 to adjust this investment to its estimated net realizable value.

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

	Years ended December 31
	2001			2000
	(in thousands)
Operations
Revenues (including equity losses)	$	4,233		$	(13,287	)
Operating loss		(233	)		(102,185	)
Interest expense		(1,050	)		(1,324	)
Income tax benefits		29			39,917
Loss from operations		(1,254	)		(63,592	)
Disposal
Loss, including provision of $7,995 for losses     from operations during phase-out period		(34,784	)		—
Income tax benefits		12,463			—
Loss on disposal		(22,321	)		—
Loss from discontinued operations of HEIPC	$	(23,575	)	$	(63,592	)

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As of December 31, 2002, the remaining net assets of the discontinued international power operations, after the write-offs and writedowns described above, amounted to $13 million (included in “Other” assets) and consisted primarily of the $7 million investment in CEPALCO and deferred taxes receivable, reduced by a reserve for losses from operations during the phase-out period. The amounts that HEIPC will ultimately realize from the disposition or sale of the international power assets could differ materially from the recorded amounts. This could occur, for example, if the HEIPC Group is successful in recovery of the costs incurred in connection with the China joint venture interest, if the investment in CEPALCO is disposed of for less or more than $7 million or if the Internal Revenue Service does not accept HEI’s treatment of the write-off of its indirect investment in EAPRC as an ordinary loss for federal corporate income tax purposes. In addition, further losses from the discontinued international power operations may be sustained during the phase-out period if the expenditures made in seeking recovery of the costs incurred in connection with the China joint venture interest exceed the total of any recovery ultimately achieved and the amount provided for in HEI’s reserve for discontinued operations.

Malama Pacific Corp. (MPC). On September 14, 1998, the HEI Board of Directors adopted a plan to exit the residential real estate development business (engaged in by MPC and its subsidiaries). Accordingly, MPC management commenced a program to sell all of MPC’s real estate assets and investments and HEI reported MPC as a discontinued operation in the Company’s consolidated statements of income in 1998. Operating activity of the residential real estate development business for the period September 14, 1998 through December 31, 2002 was not significant. In 2001, deferred tax assets and final offsite obligations on properties previously sold were adjusted, and the Company increased the loss reserve by $0.5 million.

As of December 31, 2002, the remaining net assets of the discontinued residential real estate development operations amounted to $4 million (included in “Other” assets) and consisted primarily of receivables and deferred tax assets. The amounts that MPC will ultimately realize from these assets could differ materially from the recorded amounts.

14• Fair value of financial instruments

The Company used the following methods and assumptions to estimate the fair value of each applicable class of financial instruments for which it is practicable to estimate that value:

Cash and equivalents and short-term borrowings. The carrying amount approximated fair value because of the short maturity of these instruments.

Investment and mortgage-related securities. Fair value was based on quoted market prices or dealer quotes or estimated by discounting the expected future cash flows using current market rates for similar investments.

Loans receivable. For certain categories of loans, such as some residential mortgages, credit card receivables, and other consumer loans, fair value was estimated using the quoted market prices for securities backed by similar loans, adjusted for differences in loan characteristics and estimated servicing. The fair value of other types of loans was estimated by discounting the future cash flows using the current rates at which similar loans would be made to borrowers with similar credit ratings and for similar remaining maturities.

Deposit liabilities. The fair value of demand deposits, savings accounts, and money market deposits was the amount payable on demand at the reporting date. The fair value of fixed-maturity certificates of deposit was estimated by discounting the future cash flows using the rates currently offered for deposits of similar remaining maturities.

Securities sold under agreements to repurchase. Fair value was estimated by discounting future cash flows using the current rates available for repurchase agreements with similar terms and remaining maturities.

Advances from Federal Home Loan Bank and long-term debt. Fair value was estimated by discounting the future cash flows using the current rates available for borrowings with similar remaining maturities.

HEI- and HECO-obligated preferred securities of trust subsidiaries. Fair value was based on quoted market prices.

Off-balance sheet financial instruments. The fair values of off-balance sheet financial instruments were estimated based on the fees currently charged to enter into similar agreements, taking into account the remaining

75

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

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

	December 31
	2002				2001
	Carrying or notional amount		Estimated fair value		Carrying or notional amount		Estimated fair value
	(in thousands)
Financial assets
Cash and equivalents	$	244,525	$	244,525	$	450,827	$	450,827
Available-for-sale investment and mortgage-related securities		2,744,650		2,744,650		2,370,459		2,370,459
Held-to-maturity investment securities		89,545		89,545		84,211		84,211
Loans receivable, net		2,993,989		3,108,659		2,857,622		2,965,857
Financial liabilities
Deposit liabilities		3,800,772		3,838,317		3,679,586		3,702,717
Securities sold under agreements to repurchase		667,247		685,022		683,180		684,543
Advances from Federal Home Loan Bank		1,176,252		1,248,001		1,032,752		1,078,744
Long-term debt		1,106,270		1,146,368		1,145,769		1,114,032
HEI-  and HECO-obligated preferred     securities of trust subsidiaries		200,000		200,720		200,000		201,520
Off-balance sheet items
Loans serviced for others		887,158		6,776		1,057,273		13,186
Unused lines and letters of credit		701,467		44,539		662,428		21,582

At December 31, 2002 and 2001, neither the commitment fees received on commitments to extend credit nor the fair value thereof were significant to the Company’s consolidated financial statements.

Limitations. The Company makes fair value estimates at a specific point in time, based on relevant market information and information about the financial instrument. These estimates do not reflect any premium or discount that could result if the Company were to sell its entire holdings of a particular financial instrument at one time. Because no market exists for a significant portion of the Company’s financial instruments, fair value estimates cannot be determined with precision. Changes in assumptions could significantly affect the estimates.

Fair value estimates are provided for certain financial instruments without attempting to estimate the value of anticipated future business and the value of assets and liabilities that are not considered financial instruments. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates and have not been considered.

76

15. Quarterly information (unaudited)

Selected quarterly information was as follows:

	Quarters ended												Year ended December 31
	March 31			June 30			Sept. 30			Dec.31
	(in thousands, except per share amounts)
2002
Revenues	$	377,436		$	409,002		$	431,560		$	435,703		$	1,653,701
Operating income1		64,604			70,626			71,738			59,465			266,433
Net income1		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 share5
High		44.45			47.80			46.98			49.00			49.00
Low		39.35			41.50			34.55			41.73			34.55
2001
Revenues	$	433,337		$	427,339		$	447,292		$	419,309		$	1,727,277
Operating income1		64,934			64,700			69,051			57,488			256,173
Net income1
Continuing operations		27,764			26,112			28,666			25,204			107,746
Discontinued operations2		(19	)		(524	)		(21,532	)		(1,966	)		(24,041	)
		27,745			25,588			7,134			23,238			83,705
Basic earnings (loss) per common share 3
Continuing operations		0.84			0.78			0.85			0.73			3.19
Discontinued operations2		—			(0.02	)		(0.64	)		(0.06	)		(0.71	)
		0.84			0.76			0.21			0.67			2.48
Diluted earnings (loss) per common share4
Continuing operations		0.83			0.78			0.84			0.73			3.18
Discontinued operations2		—			(0.02	)		(0.63	)		(0.06	)		(0.71	)
		0.83			0.76			0.21			0.67			2.47
Dividends per common share		0.62			0.62			0.62			0.62			2.48
Market price per common share5
High		37.75			38.40			41.25			40.90			41.25
Low		33.56			35.75			36.12			36.80			33.56

¹ For 2002, amounts reflect stock option compensation expense under the fair value based method of accounting prescribed by SFAS No. 123, as amended. For 2001, amounts reflect stock option compensation expense under the intrinsic value-based method of accounting prescribed by APB Opinion No. 25 and related interpretations. Also, for 2002, goodwill is no longer amortized as prescribed by SFAS No. 142.

² For 2001, amounts for the third quarter include the write-off of the China project, writedown of an investment in CEPALCO and establishment of a reserve for losses from operations during the phase-out period of the discontinued international power operations ($34.8 million pretax, $22.3 million after tax).

³ The quarterly basic earnings (loss) per common share are based upon the weighted-average number of shares of common stock outstanding in each quarter.

⁴ The quarterly diluted earnings (loss) per common share are based upon the weighted-average number of shares of common stock outstanding in each quarter plus the dilutive incremental shares at quarter end.

⁵ Market prices of HEI common stock (symbol HE) shown are as reported on the NYSE Composite Tape.

77

The application of SFAS No. 123, as amended, increased net income for the nine months ended September 30, 2002 by $1.2 million, or $0.03 per share. Previously reported net income, and basic and diluted earnings per share for the quarters ended March 31, 2002, June 30, 2002 and September 30, 2002, were restated as follows:

	Quarters ended
	March 31, 2002			June 30, 2002			September 30, 2002
	(in thousands, except per share amounts)
Net income, as reported	$	26,919		$	30,984		$	32,777
Add: Stock option expense included in reported net income, net of tax benefits		131			674			945
Deduct: Total stock option expense determined under the fair value based method, net of tax benefits		(178	)		(200	)		(210	)
Restated net income	$	26,872		$	31,458		$	33,512
Earnings per share
Basic—as reported	$	0.75		$	0.86		$	0.90
Basic—restated	$	0.75		$	0.87		$	0.92
Diluted—as reported	$	0.75		$	0.85		$	0.89
Diluted—restated	$	0.75		$	0.86		$	0.91

78

HEI Directors
Robert F. Clarke, 60 (1)*	T. Michael May, 56*	Oswald K. Stender, 71 (3, 4)
Chairman, President and	President and Chief Executive Officer	Real estate consultant
Chief Executive Officer	Hawaiian Electric Company, Inc.	1993
Hawaiian Electric Industries, Inc.	1995
1989		Kelvin H. Taketa, 48 (2, 3)
	Bill D. Mills, 51 (1, 2, 3, 4)	President and Chief Executive Officer
Don E. Carroll, 61 (2, 3, 4)	Chairman	Hawaii Community Foundation
Chairman	Bill Mills Investment Company	(statewide charitable foundation)
Oceanic Cablevision	(real estate development)	1993
(cable television broadcasting)	1988
1996		Jeffrey N. Watanabe, 60 (1, 4)*
	A. Maurice Myers, 62 (3, 4)	Managing Partner
Shirley J. Daniel, Ph.D., 49 (2)*	Chairman, President and	Watanabe, Ing, Kawashima & Komeiji LLP
Professor of Accountancy	Chief Executive Officer	(private law firm)
University of Hawaii-Manoa	Waste Management, Inc.	1987
College of Business Administration	(environmental services)
(higher education)	1991
2002
	Diane J. Plotts, 67 (1, 2, 3)*
Constance H. Lau, 50*	Business advisor	Committees of the Board of Directors
President and Chief Executive Officer	1987	(1) Executive:
American Savings Bank, F.S.B.		Jeffrey N. Watanabe, Chairman
2001	James K. Scott, Ed.D., 51 (2, 4)*	(2) Audit:
	President	Bill D. Mills, Chairman
Victor Hao Li, S.J.D., 61 (2)	Punahou School	(3) Compensation:
Co-chairman	(private education)	Diane J. Plotts, Chairman
Asia Pacific Consulting Group	1995	(4) Nominating & Corporate Governance:
(international business consultant)		Jeffrey N. Watanabe, Chairman
1988

*Also member of one or more subsidiary boards.

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

Information as of February 12, 2003.

HEI Executive Officers
Robert F. Clarke, 60	Charles F. Wall, 63	T. Michael May, 56 *
Chairman, President and	Vice President and	President and Chief Executive Officer
Chief Executive Officer	Corporate Information Officer	Hawaiian Electric Company, Inc.
1987	1990	1992
Eric K. Yeaman, 35	Andrew I. T. Chang, 63	Constance H. Lau, 50 *
Financial Vice President, Treasurer	Vice President–Government Relations	President and Chief Executive Officer
and Chief Financial Officer	1985	American Savings Bank, F.S.B.
2003		1984
	Curtis Y. Harada, 47
Peter C. Lewis, 68	Controller
Vice President–Administration and	1989
Corporate Secretary
1968

* Deemed to be an executive officer of HEI under SEC Rule 3b-7.

Year denotes year of first employment by the Company.

Information as of February 12, 2003.

79

Stockholder Information

Corporate headquarters

Hawaiian Electric Industries, Inc.

900 Richards Street                 P. O. Box 730

Honolulu, Hawaii 96813         Honolulu, Hawaii 96808-0730

Telephone: 808-543-5662

Facsimile: 808-543-7966

New York Stock Exchange

Common stock symbol: HE

Trust preferred securities symbols: HEPrS (HEI),

HEPrQ and HEPrT (HECO)

Shareholder Services

P. O. Box 730

Honolulu, Hawaii 96808-0730

Telephone: 808-532-5841

Facsimile: 808-532-5868

E-mail: invest@hei.com

Office hours: 7:30 a.m. to 4:00 p.m. Hawaii standard time

Correspondence about common stock and utility preferred stock ownership, dividend payments, transfer requirements, changes of address, lost stock certificates, duplicate mailings and account status may be directed to Shareholder Services.

After March 31, 2003, a copy of the Form 10-K annual report for 2002 for Hawaiian Electric Industries, Inc. and Hawaiian Electric Company, Inc., including financial statements and schedules, may be obtained from HEI upon written request without charge from Shareholder Services at the above address or through HEI’s website.

Website

Internet users can access information about HEI and its subsidiaries at http://www.hei.com.

Company news on call

1-888-943-4329 (9HEIFAX)

Our toll free, automated voice response system allows shareholders to listen to recorded dividend and earnings information, news releases, stock quotes and the answers to frequently asked stockholder questions, or to request faxed or mailed copies of various documents.

Dividends and distributions

Common stock quarterly dividends are customarily paid on or about the 10^th of March, June, September and December to stockholders of record on or about the 10^th of February, May, August and November.

Quarterly distributions on trust preferred securities are paid by Hawaiian Electric Industries Capital Trust I and HECO Capital Trusts I and II on or about March 31, June 30, September 30 and December 31 to holders of record on the business day before the distribution is paid.

Utility company preferred stock quarterly dividends are paid on the 15^th of January, April, July and October to preferred stockholders of record on the 5^th of these months.

Dividend reinvestment and stock purchase plan

Any individual of legal age or any entity may buy HEI common stock at market prices directly from the Company. The minimum initial investment is $250. Additional optional cash investments may be as small as $25. The annual maximum investment is $120,000. After your account is open, you may reinvest all of your dividends to purchase additional shares, or elect to receive some or all of your dividends in cash. You may instruct the Company to electronically debit a regular amount from a checking or savings account. The Company also can deposit dividends automatically to your checking or savings account. A prospectus describing the plan may be obtained through HEI’s website or by contacting Shareholder Services.

Annual meeting

Tuesday, April 22, 2003, 9:30 a.m.

American Savings Bank Tower

1001 Bishop Street – 8^th Floor, Room 805

Honolulu, Hawaii 96813

Please direct inquiries to:

Peter C. Lewis

Vice President – Administration and Corporate Secretary

Telephone: 808-543-7900

Facsimile: 808-543-7523

Independent auditors

KPMG LLP

Pauahi Tower

1001 Bishop Street – Suite 2100

Honolulu, Hawaii 96813

Telephone: 808-531-7286

Institutional investor and securities analyst inquiries

Please direct inquiries to:

Suzy P. Hollinger

Manager, Investor Relations

Telephone: 808-543-7385

Facsimile: 808-543-7966

E-mail: shollinger@hei.com

Transfer agents

Common stock and utility company preferred stock:

Shareholder Services

Common stock only:

Continental Stock Transfer & Trust Company

17 Battery Place, 8^th Floor

New York, New York 10004

Telephone: 212-509-4000

Facsimile: 212-509-5150

Trust preferred securities:

Contact your investment broker for information on transfer procedures.

80

EX-13.2

HECO Exhibit 13.2

Contents

Forward-Looking Statements	2
Background of the Company	3
Company Profile	3
Selected Financial Data	4
Management’s Discussion and Analysis of Financial Condition and Results of Operations	5
Quantitative and Qualitative Disclosures about Market Risk	22
Independent Auditors’ Report	23
Consolidated Financial Statements:
Consolidated Statements of Income	24
Consolidated Statements of Retained Earnings	24
Consolidated Balance Sheets	25
Consolidated Statements of Capitalization	26
Consolidated Statements of Cash Flows	28
Notes to Consolidated Financial Statements	29
Consolidated Operating Statistics	58
Directors and Executive Officers	59
Other Stockholder Information	60

1

Forward-Looking Statements

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

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

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

• the effects of weather and natural disasters;

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

• the timing and extent of changes in interest rates;

• the risks inherent in changes in the value of pension and other retirement plan assets;

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

• product demand and market acceptance risks;

• increasing competition in the electric utility industry;

• capacity and supply constraints or difficulties;

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

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

• the ability of the Company to negotiate favorable collective bargaining agreements;

• new technological developments that could affect the operations and prospects of the Company or its competitors;

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

• the risks associated with the geographic concentration of the Company businesses;

• the effects of changes in accounting principles applicable to the Company;

• the effects of changes by securities rating agencies in the ratings of the securities of the Company;

• the results of financing efforts;

• the ultimate outcome of tax positions taken;

• the risks of suffering losses that are uninsured; and

• other risks or uncertainties described elsewhere in this report and in other periodic reports previously and subsequently filed by the Company with the Securities and Exchange Commission.

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

2

Selected Financial Data

Hawaiian Electric Company, Inc. and Subsidiaries

	Years ended December 31
	2002			2001			2000			1999			1998
	(in thousands)
Income statement data
Operating revenues	$	1,252,929		$	1,284,312		$	1,270,635		$	1,050,323		$	1,008,899
Operating expenses		1,117,772			1,148,980			1,137,474			927,482			892,747
Operating income		135,157			135,332			133,161			122,841			116,152
Other income		7,095			7,436			9,935			8,054			16,832
Income before interest and other charges		142,252			142,768			143,096			130,895			132,984
Interest and other charges		50,967			53,388			54,730			54,495			48,754
Income before preferred stock dividends of HECO		91,285			89,380			88,366			76,400			84,230
Preferred stock dividends of HECO		1,080			1,080			1,080			1,178			3,454
Net income for common stock	$	90,205		$	88,300		$	87,286		$	75,222		$	80,776
	At December 31
	2002			2001			2000			1999			1998
	(dollars in thousands)
Balance sheet data
Utility plant	$	3,381,316		$	3,270,855		$	3,162,779		$	3,034,517		$	2,925,344
Accumulated depreciation		(1,367,954	)		(1,266,332	)		(1,170,184	)		(1,076,373	)		(982,172	)
Net utility plant	$	2,013,362		$	2,004,523		$	1,992,595		$	1,958,144		$	1,943,172
Total assets	$	2,436,386		$	2,389,738		$	2,392,858		$	2,302,809		$	2,311,253
Capitalization:1
Short-term borrowings from non-affiliates and affiliate	$	5,600		$	48,297		$	113,162		$	107,013		$	139,413
Long-term debt		705,270			685,269			667,731			646,029			621,998
Preferred stock subject to mandatory redemption		—			—			—			—			33,080
Preferred stock not subject to mandatory redemption		34,293			34,293			34,293			34,293			48,293
HECO-obligated preferred securities of subsidiary trusts		100,000			100,000			100,000			100,000			100,000
Common stock equity		923,256			877,154			825,012			806,103			786,567
Total capitalization	$	1,768,419		$	1,745,013		$	1,740,198		$	1,693,438		$	1,729,351
Capital structure ratios (%)1
Debt		40.2			42.0			44.9			44.5			44.0
Preferred stock		1.9			2.0			2.0			2.0			4.7
HECO-obligated preferred securities of subsidiary trusts		5.7			5.7			5.7			5.9			5.8
Common stock equity		52.2			50.3			47.4			47.6			45.5

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

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

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

4

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

The following discussion should be read in conjunction with the consolidated financial statements and accompanying notes.

Strategy

The Company’s strategy is to achieve satisfactory returns by containing costs and ensuring customer satisfaction through reliable service and close customer relationships. The success of the Company’s strategy will be heavily influenced by Hawaii’s general economic conditions and tourism. With large power users in the Company’s service territories, such as the U.S. military, hotels and state and local government, management believes that maintaining customer satisfaction is a critical component in achieving kilowatthour (KWH) sales and revenue growth in Hawaii over time. The Company has established programs that offer these customers specialized services and energy efficiency audits to help them save on energy costs. Reliability projects remain a priority for the Company. For example, on Oahu, planning has begun for an overhaul and interface of key operating systems, including a new system operations center (subject to approval by the Public Utilities Commission) integrated with new customer information and outage management systems to ensure the most efficient deployment of generators and earlier and faster responses to outages. The Company’s long-term plan to meet Hawaii’s future energy needs also includes its support of energy conservation and efficiency through demand-side management programs and initiatives to pursue a range of energy choices, including renewable energy and new power supply technologies such as distributed generation.

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

Results of operations

Net income for common stock for 2002 was $90.2 million compared to $88.3 million for 2001 and $87.3 million for 2000. The 2002 net income represents a 10.0% return on the average amount of common stock equity invested in the Company, compared to returns of 10.4% in 2001 and 10.7% in 2000. Net income for 2002 increased 2.2% from 2001 as KWH sales increased 1.9% and interest expense decreased 6%. Net income for 2001 increased 1.2% from 2000 due primarily to a 1.1% increase in KWH sales and a HELCO rate increase.

Economic conditions

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

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

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

Hawaii’s economy is expected to continue to have moderate growth in 2003, barring a war with Iraq, a conflict or crisis with North Korea or other global developments that would heighten international security concerns or

5

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

Sales

Consolidated sales of electricity were 9,544 million KWHs for 2002, 9,370 million KWHs for 2001, and 9,272 million KWHs for 2000. Despite slightly cooler temperatures, which typically result in lower residential and commercial air conditioning usage, KWH sales increased by 1.9% in 2002 partly due to an increase in the number of residential customers, higher customer KWH usage primarily by residential customers, and a recovery in the local economy following the events of the September 11, 2001 terrorist attacks. KWH sales for the fourth quarter of 2002 increased by 2.9% over the fourth quarter of 2001.

The 1.1% increase in KWH sales in 2001 was primarily due to warmer temperatures, which typically result in higher residential and commercial air conditioning usage, and an increase in the number of customers. Through August 2001, KWH sales were up 1.6%. However, declining tourism and the weakened economy after the September 11, 2001 terrorist attacks caused a 0.4% decrease in KWH sales in the fourth quarter 2001 compared to the fourth quarter 2000.

Operating revenues

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

Operating revenues were $1,252.9 million in 2002, compared to $1,284.3 million in 2001 and $1,270.6 million in 2000. The 2002 decrease in operating revenues of $31.4 million, or 2.4%, was due to lower energy prices which were passed on to customers ($59.6 million), partially offset by a 1.9% increase in KWH sales ($24.8 million). The 2001 increase in operating revenues of $13.7 million, or 1.1% over 2000, was due to a 1.1% increase in KWH sales ($12.2 million) and a HELCO rate increase ($6.0 million), partially offset by lower energy prices which were passed through to customers ($8.7 million).

Operating expenses

Total operating expenses were $1,117.8 million in 2002 compared to $1,149.0 million in 2001 and $1,137.5 million in 2000. The decrease in 2002 was due to decreased expenses for fuel oil, purchase power and taxes other than income taxes, partially offset by higher other operation, maintenance, and depreciation expenses. The increase in 2001 was due to increases in expenses for purchased power, other operation, depreciation and taxes other than income taxes, partly offset by a decrease in fuel oil and maintenance expenses.

Fuel oil expense was $310.6 million in 2002 compared to $346.7 million in 2001 and $362.9 million in 2000. The 10.4% decrease in 2002 was due primarily to lower fuel oil prices, partly offset by more KWHs generated. The 4.5 % decrease in 2001 was due primarily to lower KWHs generated. In 2002, the Company paid an average of $29.10 per barrel for fuel oil, compared to $33.49 in 2001 and $33.44 in 2000.

Purchased power expense was $326.5 million in 2002 compared to $337.8 million in 2001 and $311.2 million in 2000. The decrease in purchased power expense in 2002 was due to lower fuel prices, lower purchased capacity payments to an independent power producer (IPP) who was able to produce only an average of about 5.6 megawatts (MW) of firm capacity since April 2002, compared to the 30 MW the IPP contracted to provide to HELCO, and lower KWHs purchased. The increase in purchased power expense in 2001 was due to higher purchased capacity payments resulting from increased capacity (including a new IPP, Hamakua Partners, in August 2000), higher availability and more KWHs purchased, partially offset by lower energy prices. Purchased

6

KWHs provided approximately 38.0% of the total energy net generated and purchased in 2002 compared to 39.0% in 2001 and 36.4% in 2000.

Other operation expenses totaled $131.9 million in 2002, compared to $125.6 million in 2001 and $123.8 million in 2000. The increase in other operation expenses in 2002 was primarily due to higher employee benefits expense, including $7 million lower retirement benefits income, net of amounts capitalized, primarily due to a 25 basis points lower discount rate and the decline in the market performance of plan assets—i.e., $10 million retirement benefits income in 2002 compared to $17 million in 2001. The increase in other operation expenses in 2001 was primarily due to higher injuries and damages expense, partially offset by lower production operation expenses. HEI charges for general management, administrative and support services totaled $2.2 million in 2002, $2.0 million in 2001 and $1.8 million in 2000.

Maintenance expenses in 2002 of $66.5 million increased by $4.7 million from 2001 due primarily to a larger scope and timing of generating unit overhauls, higher production corrective maintenance and higher transmission and distribution maintenance work. Maintenance expenses in 2001 of $61.8 million decreased by $4.3 million from 2000 due primarily to lower production maintenance expenses largely due to less station maintenance expenses, and less transmission and distribution maintenance work.

Depreciation expense was up 4.7% in 2002 to $105.4 million and up 2.2% in 2001 to $100.7 million. In both years, the increases reflect depreciation on additions to plant in service in the previous year. Major additions to plant in service included HECO’s Archer-Kewalo 138 kilovolt (KV) Line #2, Kewalo-Kamoku 138 KV line and Waiau Water Treatment System in 2001 and HECO’s Archer-Kewalo 138 KV Line #1 and MECO’s 20MW combustion turbine Maalaea Unit 19 in 2000.

Taxes, other than income taxes, decreased by 0.6% in 2002 to $120.1 million and increased by 0.9% in 2001 to $120.9 million. These taxes consist primarily of taxes based on revenues, and the increases in these taxes reflect the corresponding increases in each year’s operating revenues. In 2002, the lower taxes, other than income taxes, resulting from a decrease in operating revenues, were partially offset by a $2 million non-recurring PUC fee adjustment.

Operating income

Operating income for 2002 decreased 0.1% compared to 2001 due to higher other operation, maintenance and depreciation expenses, partially offset by higher KWH sales and lower fuel oil and purchased power expenses. Operating income for 2001 increased 1.6% compared to 2000 due to higher KWH sales and lower maintenance expenses, partially offset by higher other operation and depreciation expenses.

Other income

Other income for 2002 totaled $7.1 million, compared to $7.4 million for 2001 and $9.9 million for 2000. The decreases in 2002 and 2001 were due largely to lower Allowance for Equity Funds Used During Construction (AFUDC-Equity) due to the lower base on which AFUDC-Equity was calculated.

Interest and other charges

Interest and other charges for 2002 totaled $51.0 million, compared to $53.4 million for 2001 and $54.7 million for 2000. Interest and other charges included $7.7 million of preferred securities distributions by HECO’s trust subsidiaries each year in 2002, 2001 and 2000. See Note 3 in the “Notes to Consolidated Financial Statements” for a discussion of the preferred securities issued by the trust subsidiaries.

Interest on long-term debt for 2002 of $40.7 million, compared to $40.3 million for 2001 and $40.1 million for 2000 reflect interest on drawdowns of tax-exempt Special Purpose Revenue Bonds (SPRB) during the year and the full year’s interest on the prior year’s drawdowns of SPRB proceeds, partially offset by lower bond interest rates. In January 2002, HELCO’s $2 million of 7 ⁷/8% Series J First Mortgage Bonds (FMB) and $3 million of 7 ³/4% Series K FMB were redeemed. In November 2000, $21 million of 7.6% Series 1990B SPRB and $45 million of 7 ³/8% Series 1990C SPRB were refinanced using proceeds from the 5.7% Series 2000 SPRB.

Other interest charges were $1.5 million for 2002, compared to $4.7 million for 2001 and $7.0 million for 2000. The decreases in 2002 and 2001 were primarily due to lower short-term borrowings and lower short-term interest rates.

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Recent rate requests

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

Hawaiian Electric Company, Inc. HECO has not initiated a rate case for several years, but in 2001 it committed to initiate a rate case within three years, using a 2003 or 2004 test year, as part of the agreement described below under “Other regulatory matters, Demand-side management programs—agreements with the Consumer Advocate.” In October 2002, HECO filed an application with the PUC for approval to change its depreciation rates and to change to vintage amortization accounting for selected plant accounts, which changes would have amounted to an estimated $4.2 million, or 6.3%, increase in depreciation expense based on a study of depreciation expense for 2000. In its application, HECO requested that the effective date of the proposed changes coincide with the effective date of the rates established in HECO’s next rate case proceeding so that HECO’s financial results would not be negatively impacted by the depreciation rates and method ultimately approved by the PUC.

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

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

Other regulatory matters

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

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

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

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

Collective bargaining agreements

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

Legislation

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

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

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up to 10 kilowatts (i.e., a customer-generator may be a net user or supplier of energy and will make payments to or receive credits from the electric utility accordingly).

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

Effects of inflation

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

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

Recent accounting pronouncements

See “Recent accounting pronouncements” in Note 1 of the “Notes to Consolidated Financial Statements.”

Liquidity and capital resources

The Company believes that its ability to generate cash, both internally from operations and externally from issuances of equity and debt securities, commercial paper and bank borrowings, is adequate to maintain sufficient liquidity to fund its construction programs and to cover debt and other cash requirements in the foreseeable future.

The Company’s total assets were $2.4 billion at December 31, 2002 and 2001.

The consolidated capital structure of the Company was as follows:

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

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

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

NR    Not rated.

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

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

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

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

At December 31, 2002, HECO maintained bank lines of credit totaling $100 million (all maturing in 2003). On January 1, 2003, HECO reduced its total lines of credit to $90 million. These lines of credit are principally maintained by HECO to support the issuance of commercial paper and may be drawn for general corporate purposes. Accordingly, the lines of credit are available for short-term liquidity in the event a rating agency downgrade was to reduce or eliminate access to the commercial paper markets. None of HECO’s line of credit agreements contain “material adverse change” clauses that would affect access to the lines of credit in the event of a ratings downgrade or other material adverse events. At December 31, 2002, the lines were unused. To the extent deemed necessary, HECO anticipates arranging similar lines of credit as existing lines of credit mature. See S&P and Moody’s ratings above and Note 5 in the “Notes to Consolidated Financial Statements.”

Capital expenditures requiring the use of cash, as shown on the “Consolidated Statements of Cash Flows,” totaled approximately $114.6 million in 2002, of which $71.3 million was attributable to HECO, $27.6 million to HELCO and $15.7 million to MECO. Approximately 64% of the total 2002 capital expenditures were for transmission and distribution projects and approximately 36% was for generation and general plant projects. Cash contributions in aid of construction received in 2002 totaled $11.0 million.

In 2002, the Company’s investing activities used $103.5 million in cash, primarily for capital expenditures. Financing activities used net cash of $68.2 million, including $52.9 million for the payment of common and preferred stock dividends and trust preferred securities distributions, $42.7 million for the net repayment of short-term borrowings, partly offset by a $30.3 million net increase in long-term debt. Operating activities provided cash of $171.6 million.

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

As of December 31, 2002, $16.1 million of proceeds from the Series 2002A sale by the Department of Budget and Finance of the State of Hawaii of special purpose revenue bonds issued for the benefit of HECO remain undrawn. Also as of December 31, 2002, an additional $25 million of special purpose revenue bonds were authorized by the Hawaii Legislature for issuance by the Department of Budget and Finance of the State of Hawaii for the benefit of HELCO prior to the end of 2003.

As further explained in Note 10 in the “Notes to Consolidated Financial Statements,” the Company participates in pension and other postretirement benefit plans. Funding for the pension plans is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under the Employee Retirement Income Security Act of 1974, as amended (ERISA). The Company is not required to make any contributions to the pension plans to meet minimum funding requirements pursuant to ERISA for 2003, but the HEI Pension Investment Committee (PIC) may choose to make contributions to the pension plans in 2003. The Company’s policy is to comply with directives from the PUC to fund the costs of the postretirement benefit plan. These costs are ultimately collected in rates billed to customers. The HEI PIC reserves the right to change, modify or terminate the pension plans and the Company reserves the right to change, modify or terminate its postretirement benefit plan. From time to time in the past, benefits have changed. Due to the sharp declines in U.S. equity markets beginning in 2000, the value of a significant portion of the assets held in the plans’ trusts to satisfy the obligations of the pension and other postretirement plans has decreased significantly. As a result, additional contributions may be required in the future to meet the minimum funding requirements of ERISA or to pay benefits to plan participants. The Company believes it will have adequate access to capital resources to support any necessary funding requirements.

The Company’s consolidated financing requirements for 2003 through 2007, including net capital expenditures and long-term debt repayments, are estimated to total $0.7 billion. Consolidated internal sources (primarily consolidated cash flows from operations comprised mainly of net income, adjusted for noncash income and expense items such as depreciation, amortization and deferred taxes, and changes in working capital), after the payment of common stock and preferred stock dividends, are expected to provide cash in excess of the consolidated financing requirements and may be used to reduce the level of borrowings. HECO does not anticipate the need to issue common equity over the five-year period 2003 through 2007. Debt and/or equity financing may be required, however, to fund unanticipated expenditures not included in the 2003 through 2007 forecast, such as increases in the costs of or an acceleration of the construction of capital projects, unbudgeted acquisitions or investments in new businesses and significant increases in retirement benefit funding requirements that might be required if there were significant declines in the market value of pension plan assets or changes in actuarial assumptions. The PUC must approve issuances, if any, of equity and long-term debt securities by HECO, HELCO and MECO.

Capital expenditures include the costs of projects that are required to meet expected load growth, to improve reliability and to replace and upgrade existing equipment. Net capital expenditures for the five-year period 2003 through 2007 are currently estimated to total $0.7 billion. Approximately 53% of forecast gross capital expenditures, which includes AFUDC and capital expenditures funded by third-party contributions in aid of construction, is for transmission and distribution projects, with the remaining 47% primarily for generation projects.

For 2003, net capital expenditures are estimated to be $158 million. Gross capital expenditures are estimated to be $183 million, including approximately $103 million for transmission and distribution projects, approximately $58 million for generation projects and approximately $22 million for general plant and other projects. Drawdowns of the remaining $16.1 million of proceeds from the Series 2002A sale of tax-exempt special purpose revenue bonds and the generation of funds from internal sources are expected to provide the cash needed for the net capital expenditures in 2003.

Management periodically reviews capital expenditure estimates and the timing of construction projects. These estimates may change significantly as a result of many considerations, including changes in economic conditions, changes in forecasts of KWH sales and peak load, the availability of purchased power and changes in expectations concerning the construction and ownership of future generating units, the availability of generating sites and transmission and distribution corridors, the ability to obtain adequate and timely rate increases,

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escalation in construction costs, the impacts of DSM programs, the effects of opposition to proposed construction projects and requirements of environmental and other regulatory and permitting authorities.

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

Selected contractual obligations

The following tables present aggregated information about certain contractual obligations and commercial commitments:

December 31, 2002	Payment due by period
	Less than 1 year		1-3 years		4-5 years		After 5 years		Total
	(in millions)
Contractual obligations
Long-term debt	$	—	$	—	$	—	$	726	$	726
HECO-obligated preferred securities of trust subsidiaries		—		—		—		100		100
Operating leases		2		3		1		2		8
Fuel oil purchase obligations (estimate based on January 1, 2003 fuel oil prices)		329		330		—		—		659
Purchase power obligations–minimum fixed capacity charges		123		241		236		1,607		2,207
	$	454	$	574	$	237	$	2,435	$	3,700

The tables above do not include other categories of obligations and commitments, such as trade payables, obligations under purchase orders and amounts that may become payable in future periods under collective bargaining and other employment agreements and employee benefit plans.

Certain factors that may affect future results and financial condition

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

Economic conditions

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

Competition

The electric utility industry in Hawaii has become increasingly competitive. IPPs are well established in Hawaii and continue to actively pursue new projects. Competition in the generation sector in Hawaii is moderated, however, by the scarcity of generation sites, various permitting processes and lack of interconnections to other electric utilities. Customer self-generation, with or without cogeneration, is a continuing competitive factor. Historically, HECO and its subsidiaries have been able to compete by offering customers economic alternatives that, among other things, employ energy efficient electrotechnologies such as the heat pump water heater. However, the number of customer self-generation projects that are being proposed or installed in Hawaii, particularly those involving combined heat and power (CHP) systems, is growing. CHP systems are a form of distributed generation (DG), and produce electricity and thermal energy from gas, propane or diesel-fired engines. In Hawaii, the thermal energy generally is used to heat water and, through an absorption chiller, drive an air conditioning system. The electric energy generated by these systems is usually lower in output than the customer’s load, which results in continued connection to the utility grid to make up the difference in electricity demand and to provide back up electricity.

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

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

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

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

In January 2000, the PUC submitted to the legislature a status report on its investigation of competition. The report stated that competitive bidding for new power supplies (i.e., wholesale generation competition) is a logical first step to encourage competition in Hawaii’s electric industry and that the PUC plans to proceed with an examination of the feasibility of competitive bidding and to review specific policies to encourage renewable energy resources in the power generation mix. The report states that “further steps” by the PUC “will involve the development of specific policies to encourage wholesale competition and the continuing examination of other areas suitable for the development of competition.” HECO is unable to predict the ultimate outcome of the proceeding, which of the proposals (if any) advanced in the proceeding will be implemented or whether the parties will seek and obtain state legislative action on their proposals (other than the legislation described above under “Results of operations—Legislation”).

U.S. capital markets and interest rate environment

Changes in the U.S. capital markets can have significant effects on the Company. For example, the Company estimates that retirement benefits expense, net of amounts capitalized and income taxes, will be $8 million in 2003 as compared to net retirement benefits income of $6 million in 2002 (or $14 million less net income), partly as a result of the effect of the stock market decline on the performance of the assets in HEI’s master pension trust.

HECO and its subsidiaries are exposed to interest rate risk primarily due to their borrowings. They attempt to manage this risk in part by incurring or refinancing debt in periods of low interest rates and by usually issuing fixed-rate rather than floating-rate long-term debt. As of December 31, 2002, the Company had no commercial paper outstanding.

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Technological developments

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

Limited insurance

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

Environmental matters

The Company is subject to environmental laws and regulations that regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic substances. These laws and regulations, among other things, require that certain environmental permits be obtained as a condition to constructing or operating certain facilities, and obtaining such permits can entail significant expense and cause substantial construction delays. Also, these laws and regulations may be amended from time to time, including amendments that increase the burden and expense of compliance. Management believes that the recovery through rates of most, if not all, of any costs incurred by HECO and its subsidiaries in complying with environmental requirements would be allowed by the PUC.

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

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

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

15

Regulation of electric utility rates

The PUC has broad discretion in its regulation of the rates charged by HECO, HELCO and MECO and in other matters. Any adverse D&O by the PUC concerning the level or method of determining electric utility rates, the authorized returns on equity or other matters, or any prolonged delay in rendering a D&O in a rate or other proceeding, could have a material adverse effect on the Company’s results of operations and financial condition. Upon a showing of probable entitlement, the PUC is required to issue an interim D&O in a rate case within 10 months from the date of filing a completed application if the evidentiary hearing is completed (subject to extension for 30 days if the evidentiary hearing is not completed). There is no time limit for rendering a final D&O. Interim rate increases are subject to refund with interest, pending the final outcome of the case. At December 31, 2002, HECO and its subsidiaries had recognized $16 million of revenues with respect to interim orders regarding certain integrated resource planning costs, which revenues are subject to refund, with interest, to the extent they exceed the amounts allowed in final orders.

Management cannot predict with certainty when D&Os in future rate cases will be rendered or the amount of any interim or final rate increase that may be granted. There are no rate cases pending at this time. HECO, however, has committed to file a rate increase application using a 2003 or 2004 test year.

The rate schedules of HECO, HELCO and MECO include energy cost adjustment clauses under which electric rates charged to customers are automatically adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power. In 1997 PUC decisions approving the Company’s fuel supply contracts, the PUC noted that, in light of the length of the fuel supply contracts and the relative stability of fuel prices, the need for continued use of energy cost adjustment clauses would be the subject of investigation in a generic docket or in a future rate case. HECO and its electric utility subsidiaries believe that the energy cost adjustment clauses continue to be necessary. These clauses were continued in the most recent HELCO and MECO rate cases (final D&O’s issued in February 2001 and April 1999, respectively).

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

Fuel oil and purchased power

HECO and its electric utility subsidiaries rely on fuel oil suppliers and independent power producers to deliver fuel oil and power, respectively. The Company estimates that 77% of the net energy generated and purchased in 2003 will be generated from the burning of oil. Purchased KWHs provided approximately 38.0% of the total net energy generated and purchased in 2002 compared to 39.0% in 2001 and 36.4% in 2000.

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

16

Other regulatory and permitting contingencies

Many public utility projects require PUC approval and various permits (e.g., environmental and land use permits) from other agencies. Delays in obtaining PUC approval or permits can result in increased costs. If a project does not proceed or if the PUC disallows costs of the project, the project costs may need to be written off in amounts that could have a material adverse effect on the Company. The following two major capital improvement projects, the Keahole project and the Kamoku-Pukele transmission line, have encountered opposition and the Keahole project has been seriously delayed.

Keahole project. In 1991, HELCO began planning to meet increased electric generation demand forecasted for 1994. HELCO’s plans were to install at its Keahole power plant two 20 MW combustion turbines (CT-4 and CT-5), followed by an 18 MW heat steam recovery generator, at which time these units would be converted to a 56 MW (net) dual-train combined-cycle unit. The timing of the installation of HELCO’s phased units has been revised on several occasions due to delays in obtaining an air permit and a land use permit amendment, in addition to delays caused by the commencement of lawsuits and administrative proceedings, many of which are on appeal or otherwise have not been finally resolved. See Note 11 in the “Notes to Consolidated Financial Statements” for a more detailed description of the history and status of this project.

In September 2000, the Third Circuit Court of the State of Hawaii (Circuit Court) ruled that, absent a legal or equitable extension properly authorized by the Board of Land and Natural Resources (BLNR), HELCO’s further construction of CT-4 and

CT-5 could not proceed because HELCO had not completed construction within the three-year construction period the Circuit Court found to be applicable to the project, unless the BLNR extended the construction period. HELCO subsequently obtained a BLNR order extending the construction period, but the Circuit Court then ruled, on September 19, 2002, that the BLNR did not have authority to grant the extension. As a result of this ruling, the construction of CT-4 and CT-5 has been suspended.

HELCO has appealed to the Hawaii Supreme Court both the Circuit Court 2000 ruling that there was a three-year construction period that had expired and the Circuit Court’s later ruling that BLNR could not extend the construction period. HELCO also filed motions to expedite the appeal and to stay the Circuit Court’s ruling pending the appeal. The Hawaii Supreme Court has denied the motion to expedite the appeal and the motion to stay the Circuit Court’s ruling pending appeal. In early 2003, the Hawaii Supreme Court also ruled that the appeal from the Circuit Court’s ruling in 2000 that the construction period had expired was not timely (even though the Circuit Court ruled at the time that its Order could not yet be appealed) and dismissed the appeal. HELCO cannot predict when its appeal of the Circuit Court’s ruling that the BLNR lacked authority to extend the construction deadline will be decided.

HELCO continues to consider other options that may allow HELCO to complete the installation of CT-4 and CT-5 (including seeking a land use reclassification of the Keahole site from the State Land Use Commission). If none of these options is ultimately successful and HELCO does not prevail on its appeal, HELCO may be unable to complete the installation of CT-4 and CT-5. The recovery of costs relating to CT-4 and CT-5 are subject to the rate-making process governed by the PUC. Management believes no adjustment to costs incurred to put CT-4 and CT-5 into service is required as of December 31, 2002. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HELCO may be required to write off a material portion of the costs incurred in its efforts to put these units into service whether or not CT-4 and CT-5 are installed. As of December 31, 2002, HELCO’s costs incurred in its efforts to put CT-4 and CT-5 into service and to support existing units (excluding costs the PUC permitted to be transferred to plant-in-service for pre-air permit facilities in HELCO’s most recent rate case) amounted to approximately $82 million, including $32 million for equipment and material purchases, $30 million for planning, engineering, permitting, site development and other costs and $20 million for AFUDC charged to the project prior to HELCO’s decision to discontinue the further accrual of AFUDC on CT-4 and CT-5. HELCO discontinued the accrual of AFUDC effective December 1, 1998, due in part to the delays and the potential for further delays. In addition to the $82 million in construction in progress, construction and/or purchase commitments related to CT-4 and CT-5 outstanding as of December 31, 2002 are estimated at approximately $0.6 million. See “HELCO Power Situation” in Note 11 of the “Notes to Consolidated Financial Statements.”

17

Kamoku-Pukele transmission line. HECO has for some time been expending efforts to address future potential line overloads in its two major corridors (Northern and Southern) transmitting bulk power to the Honolulu/East Oahu area, and to improve the reliability of the Pukele substation at the end of the Northern corridor. HECO planned to construct a part underground/part overhead 138 kv transmission line from the Kamoku substation to the Pukele substation in order to close the gap between the Southern and Northern transmission corridors and provide a third 138 kv transmission line to the Pukele substation. Construction of the Kamoku to Pukele transmission line in its proposed location required the BLNR to approve a Conservation District Use Permit (CDUP) for the overhead portion of the line that would have been in conservation district lands. On June 28, 2002, the BLNR issued a ruling denying HECO’s request for the CDUP.

HECO continues to believe that the proposed project is needed. HECO is evaluating alternative ways to accomplish the project, and possible future actions to expedite PUC review of the alternatives and the need for the project. As of December 31, 2002, the accumulated costs related to the Kamoku to Pukele transmission line amounted to $17 million, including $12 million for planning, engineering and permitting costs and $5 million for AFUDC. These costs are recorded in construction in progress. The recovery of costs relating to the Kamoku to Pukele transmission line project is subject to the rate-making process governed by the PUC. Management believes no adjustment to costs incurred to put the Kamoku to Pukele transmission line into service is required as of December 31, 2002. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HECO may be required to write off a material portion or all of the costs incurred in its efforts to put the Kamoku to Pukele transmission line into service whether or not the line is installed. See “Oahu transmission system” in Note 11 of the “Notes to Consolidated Financial Statements.”

Material estimates and critical accounting policies

In preparing the consolidated financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. Actual results could differ significantly from those estimates.

Material estimates that are particularly susceptible to significant change in the case of the Company include the amounts reported for regulatory assets, pension and other postretirement benefit obligations, current and deferred taxes, contingencies and litigation.

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

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

Utility plant

Utility plant is reported at cost. Self-constructed electric utility plant includes engineering, supervision, and administrative and general costs, and an allowance for the cost of funds used during the construction period. These costs are recorded in construction in progress and are transferred to utility plant when construction is completed and the facilities are either placed in service or become useful for public utility purposes. Upon the retirement or sale of electric utility plant, no gain or loss is recognized. The cost of the plant retired or sold and the cost of removal (net of salvage value) previously provided through depreciation are charged to accumulated depreciation.

Management believes that the PUC will allow recovery of utility plant in its electric rates. If the PUC does not allow recovery of any such costs, the Company would be required to write off the disallowed costs at that time. See the discussion above concerning costs recorded in construction in progress for CT-4 and CT-5 at Keahole and the proposed Kamoku-Pukele transmission line under “Certain factors that may affect future results and financial condition-Other regulatory and permitting contingencies.”

18

Pension and other postretirement benefits

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

The Company’s reported costs of providing retirement benefits (described in Note 10 in the “Notes to Consolidated Financial Statements”) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. For example, pension and other postretirement benefit costs are impacted by actual employee demographics (including age and compensation levels), the level of contributions to the plans and earnings on plan assets. Changes made to the provisions of the plans may also impact current and future costs. (No changes were made to the retirement benefit plans’ provisions in 2002, 2001 and 2000 that have had a significant impact on recorded retirement benefit plan amounts.) Costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used.

As a result of the factors listed above, significant portions of pension and other postretirement benefit costs recorded in any period do not reflect the actual benefits provided to plan participants. For 2002 and 2001, the Company recorded other postretirement benefit expense, net of amounts capitalized, of approximately $4 million and $2 million, respectively, in accordance with the provisions of SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” Actual payments of benefits made to retirees during 2002 and 2001 were $6 million and $7 million, respectively. In accordance with SFAS No. 87, “Employers’ Accounting for Pensions,” changes in pension obligations associated with the factors noted above may not be immediately recognized as pension costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. For 2002 and 2001, the Company recorded non-cash pension income, net of amounts capitalized, of approximately $14 million and $19 million, respectively, and paid benefits of $34 million and $32 million, respectively.

The assumptions used by management in making benefit and funding calculations are based on current economic conditions. Changes in economic conditions will impact the underlying assumptions in determining retirement benefit costs on a prospective basis. In selecting an assumed discount rate, the HEI PIC considers the Moody’s Aa and Aaa Daily Long-Term Corporate Bond Yield Averages, as well as yields for 20 and 30 year Treasury strips. In selecting an assumed rate of return on plan assets, the HEI PIC considers economic forecasts for the types of investments held by the plan and the past performance of plan assets.

As presented in Note 10 in the “Notes to Consolidated Financial Statements,” the HEI PIC has revised key assumptions at December 31, 2002 compared to December 31, 2001. Such changes will not have an impact on reported costs in 2002; however, for future years, such changes will have a significant impact. Based upon the revised assumptions (decreasing the discount rate 50 basis points to 6.75% and the long-term rate of return on assets 100 basis points to 9.0% as of December 31, 2002 compared to December 31, 2001), the Company estimates that retirement benefits expense, net of amounts capitalized and income taxes, will be $8 million in 2003 as compared to net retirement benefits income of $6 million in 2002 (or $14 million less net income). In determining the retirement benefit costs, these assumptions can change from period to period, and such changes could result in material changes to these estimated amounts.

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

The following tables reflect the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage and constitute “forward-looking statements.” While the tables below reflect an increase or decrease in the percentage for each assumption, the HEI PIC and its actuaries expect that the inverse of these changes would impact the projected benefit obligation (PBO) and 2003 net income in the opposite direction. Each sensitivity below reflects an evaluation of the change based solely on a change in that assumption as well as a related change in the contributions to the postretirement benefits plan.

19

	Actuarial assumption
	Change in assumption		Impact on PBO		Impact on 2003 net income
(in millions)
Pension benefits
Discount rate	(0.5	)%	$	46.0	$	(1.9	)
Rate of return on plan assets	(0.5	)		—		(1.2	)
Other benefits
Discount rate	(0.5	)		9.1		(0.1	)
Health care cost trend rate	0.5			1.9		(0.1	)
Rate of return on plan assets	(0.5	)		—		(0.2	)

Environmental expenditures

In general, environmental contamination treatment costs are charged to expense, unless it is probable that the PUC would allow such costs to be recovered in future rates, in which case such costs would be capitalized as regulatory assets. Also, environmental costs are capitalized if the costs extend the life, increase the capacity, or improve the safety or efficiency of property; the costs mitigate or prevent future environmental contamination; or the costs are incurred in preparing the property for sale. Liabilities are recorded when environmental assessments and/or remedial efforts are probable, and the cost can be reasonably estimated. Estimated costs are based upon an expected level of contamination and remediation efforts. Should the level of contamination and remediation efforts be different than initially expected, the ultimate costs will differ. See “Environmental regulation” in Note 11 of the “Notes to Consolidated Financial Statements” for a description of the Honolulu Harbor investigation.

Income taxes

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

Governmental tax authorities could challenge a tax return position taken by management, and such challenges might not be raised and finally resolved until several years after the events in question. If the Company’s position does not prevail, the Company’s results of operations and financial condition may be adversely affected as the related deferred or current income tax asset would be impaired.

20

Regulation by the PUC

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

Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. As of December 31, 2002, regulatory assets amounted to $106 million. These regulatory assets are itemized in Note 6 of the “Notes to Consolidated Financial Statements.” Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment. Because current rates include the recovery of existing regulatory assets and rates in effect allow the utilities to earn a reasonable rate of return, management believes the existing regulatory assets are probable of recovery. This determination assumes continuation of the current political and regulatory climate in Hawaii, and is subject to change in the future.

Management believes HECO and its electric utility subsidiaries’ operations currently satisfy the SFAS No. 71 criteria. However, if events or circumstances should change so that those criteria are no longer satisfied, management believes that a material adverse effect on the Company’s results of operations and financial position may result as regulatory assets would be charged to expense.

Electric utility revenues

Electric utility revenues are based on rates authorized by the PUC and include revenues applicable to energy consumed in the accounting period but not yet billed to the customers. At December 31, 2002, revenues applicable to energy consumed, but not yet billed to the customers, amounted to $60 million.

Revenue amounts recorded pursuant to a PUC interim order are subject to refund, with interest, pending a final order. At December 31, 2002, HECO and its electric utility subsidiaries had recognized $16 million of revenues with respect to interim orders regarding certain integrated resource planning costs, which revenues are subject to refund, with interest, to the extent they exceed the amounts allowed in final orders. If a refund were required, the revenues to be refunded would be immediately reversed on the income statement. The Consumer Advocate has objected to the recovery of $1.9 million (before interest) of the $8.5 million of integrated resource planning costs incurred from 1995 through 1998 and in 2001, and the PUC’s decision is pending on this matter. The Consumer Advocate has not stated its position on the recovery of the $1.5 million of integrated resource planning costs incurred from 1999 through 2000.

The rate schedules of HECO and its electric utility subsidiaries include energy cost adjustment clauses under which electric rates are adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power. If the energy cost adjustment clauses were discontinued, the Company’s results of operations could fluctuate significantly as a result of increases and decreases in fuel oil and purchased energy prices. In 1997 PUC decisions approving HECO and its electric utility subsidiaries’ fuel supply contracts, the PUC noted that, in light of the length of the fuel supply contracts and the relative stability of fuel prices, the need for continued use of energy cost adjustment clauses would be the subject of investigation in a generic docket or in a future rate case. HECO and its electric utility subsidiaries believe that the energy cost adjustment clauses continue to be necessary. These clauses were continued in the most recent HELCO and MECO rate cases.

21

Quantitative and Qualitative Disclosures about Market Risk

The Company manages various market risks in the ordinary course of business, including credit risk and liquidity risk, and believes its exposures to these risks are not material as of December 31, 2002. Because the Company does not have a portfolio of trading assets, the Company is not exposed to market risk from trading activities.

The Company is exposed to some commodity price risk primarily related to its fuel supply and IPP contracts, which is mitigated by the energy cost adjustment clauses in the Company’s rate schedules.

The Company considers interest rate risk to be a significant market risk as it could potentially have a significant effect on the Company’s results of operations and financial condition. Interest rate risk can be defined as the exposure of the Company’s earnings to adverse movements in interest rates. The Company does not currently use derivatives to manage interest rate risk. The Company’s general policy is to manage interest rate risk through use of a combination of short- and long-term debt (primarily fixed-rate debt) and preferred securities.

The tables below provide information about the Company’s market sensitive financial instruments in U.S. dollars, including contractual balances at the stated maturity dates as well as the estimated fair values as of December 31, 2002 and 2001, and constitute “forward-looking statements.”

See Note 15 in the “Notes to Consolidated Financial Statements” for descriptions of the methods and assumptions used to estimate fair value of each applicable class of financial instruments.

December 31, 2002	Expected maturity
	2003			2004	2005	2006	2007	There- after			Total			Estimated fair value
(dollars in millions)
Interest-sensitive liabilities
Short-term borrowings	$	6		—	—	—	—		—		$	6		$	6
Average interest rate		1.5	%	—	—	—	—		—			1.5	%
Long-term debt—fixed rate		—		—	—	—	—	$	705		$	705		$	736
Average interest rate		—		—	—	—	—		5.8	%		5.8	%
HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts		—		—	—	—	—	$	100		$	100		$	100
Average distribution rate		—		—	—	—	—		7.7	%		7.7	%
December 31, 2001	Expected maturity
	2002			2003	2004	2005	2006	There- after			Total			Estimated fair value
(dollars in millions)
Interest-sensitive liabilities
Short-term borrowings	$	48		—	—	—	—		—		$	48		$	48
Average interest rate		2.0	%	—	—	—	—		—			2.0	%
Long-term debt—fixed rate	$	15		—	—	—	—	$	670		$	685		$	666
Average interest rate		7.9	%	—	—	—	—		5.9	%		5.9	%
HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts		—		—	—	—	—	$	100		$	100		$	100
Average distribution rate		—		—	—	—	—		7.7	%		7.7	%

22

Independent Auditors’ Report

To the Board of Directors and Stockholder

Hawaiian Electric Company, Inc.:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Hawaiian Electric Company, Inc. (a wholly-owned subsidiary of Hawaiian Electric Industries, Inc.) and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of income, retained earnings and cash flows for each of the years in the three-year period ended December 31, 2002. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Hawaiian Electric Company, Inc. and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

/s/ KPMG LLP

Honolulu, Hawaii

January 20, 2003

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Consolidated Statements of Income

Hawaiian Electric Company, Inc. and Subsidiaries

	Years ended December 31,
	2002			2001			2000
	(in thousands)
Operating revenues	$	1,252,929		$	1,284,312		$	1,270,635
Operating expenses:
Fuel oil		310,595			346,728			362,905
Purchased power		326,455			337,844			311,207
Other operation		131,910			125,565			123,779
Maintenance		66,541			61,801			66,069
Depreciation		105,424			100,714			98,517
Taxes, other than income taxes		120,118			120,894			119,784
Income taxes		56,729			55,434			55,213
		1,117,772			1,148,980			1,137,474
Operating income		135,157			135,332			133,161
Other income:
Allowance for equity funds used during construction		3,954			4,239			5,380
Other, net		3,141			3,197			4,555
		7,095			7,436			9,935
Income before interest and other charges		142,252			142,768			143,096
Interest and other charges:
Interest on long-term debt		40,720			40,296			40,134
Amortization of net bond premium and expense		2,014			2,063			1,938
Other interest charges		1,498			4,697			6,990
Allowance for borrowed funds used during construction		(1,855	)		(2,258	)		(2,922	)
Preferred stock dividends of subsidiaries		915			915			915
Preferred securities distributions of trust subsidiaries		7,675			7,675			7,675
		50,967			53,388			54,730
Income before preferred stock dividends of HECO		91,285			89,380			88,366
Preferred stock dividends of HECO		1,080			1,080			1,080
Net income for common stock	$	90,205		$	88,300		$	87,286
Consolidated Statements of Retained Earnings
Hawaiian Electric Company, Inc. and Subsidiaries
	Years ended December 31,
	2002			2001			2000
	(in thousands)
Retained earnings, January 1	$	495,961		$	443,970		$	425,206
Net income for common stock		90,205			88,300			87,286
Common stock dividends		(44,143	)		(36,309	)		(68,522	)
Retained earnings, December 31	$	542,023		$	495,961		$	443,970

See accompanying “Notes to Consolidated Financial Statements.”

24

Consolidated Balance Sheets

Hawaiian Electric Company, Inc. and Subsidiaries

	December 31,
	2002			2001
	(in thousands)
Assets
Utility plant, at cost:
Land	$	31,896		$	31,689
Plant and equipment		3,184,818			3,068,254
Less accumulated depreciation		(1,367,954	)		(1,266,332	)
Plant acquisition adjustment, net		302			354
Construction in progress		164,300			170,558
Net utility plant		2,013,362			2,004,523
Current assets:
Cash and equivalents		1,726			1,858
Customer accounts receivable, net		87,113			81,872
Accrued unbilled revenues, net		60,098			52,623
Other accounts receivable, net		2,213			2,652
Fuel oil stock, at average cost		35,649			24,440
Materials and supplies, at average cost		19,450			19,702
Prepayments and other		75,610			53,744
Total current assets		281,859			236,891
Other assets:
Regulatory assets		105,568			111,376
Unamortized debt expense		13,354			12,443
Long-term receivables and other		22,243			24,505
Total other assets		141,165			148,324
	$	2,436,386		$	2,389,738
Capitalization and liabilities
Capitalization (see Consolidated Statements of Capitalization):
Common stock equity	$	923,256		$	877,154
Cumulative preferred stock, not subject to mandatory redemption		34,293			34,293
HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO and HECO-guaranteed debentures		100,000			100,000
Long-term debt, net		705,270			670,674
Total capitalization		1,762,819			1,682,121
Current liabilities:
Long-term debt due within one year		—			14,595
Short-term borrowings-affiliate		5,600			48,297
Accounts payable		59,992			53,966
Interest and preferred dividends payable		11,532			11,765
Taxes accrued		79,133			86,058
Other		28,020			29,799
Total current liabilities		184,277			244,480
Deferred credits and other liabilities:
Deferred income taxes		158,367			145,608
Unamortized tax credits		47,985			48,512
Other		64,844			55,460
Total deferred credits and other liabilities		271,196			249,580
Contributions in aid of construction		218,094			213,557
	$	2,436,386		$	2,389,738

See accompanying “Notes to Consolidated Financial Statements.”

25

Consolidated Statements of Capitalization

Hawaiian Electric Company, Inc. and Subsidiaries

	December 31,
	2002		2001		2000
	(dollars in thousands, except per share amounts)
Common stock equity:
Common stock of $6 2/3 par value	$	85,387	$	85,387	$	85,387
Authorized: 50,000,000 shares Outstanding: 2002, 2001 and 2000, 12,805,843 shares
Premium on capital stock		295,846		295,806		295,655
Retained earnings		542,023		495,961		443,970
Common stock equity		923,256		877,154		825,012
Cumulative preferred stock not subject to mandatory redemption:
Authorized: 5,000,000 shares of $20 par value and 7,000,000 shares of $100 par value. Outstanding: 2002 and 2001, 1,234,657 shares.

Series	Par Value			Shares Outstanding December 31, 2002	2002		2001
	(dollars in thousands, except per share amounts)
C-4 1/4%	$	20	(HECO)	150,000		3,000		3,000
D-5%		20	(HECO)	50,000		1,000		1,000
E-5%		20	(HECO)	150,000		3,000		3,000
H-5 1/4%		20	(HECO)	250,000		5,000		5,000
I-5%		20	(HECO)	89,657		1,793		1,793
J-4 3/4%		20	(HECO)	250,000		5,000		5,000
K-4.65%		20	(HECO)	175,000		3,500		3,500
G-7 5/8%		100	(HELCO)	70,000		7,000		7,000
H-7 5/8%		100	(MECO)	50,000		5,000		5,000
				1,234,657	$	34,293	$	34,293

(continued)

See accompanying “Notes to Consolidated Financial Statements.”

26

Consolidated Statements of Capitalization, continued

Hawaiian Electric Company, Inc. and Subsidiaries

	December 31,
	2002		2001
	(in thousands)
HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO and HECO-guaranteed debentures (distribution rates of 7.30% and 8.05%)	$	100,000	$	100,000
Long-term debt:
First mortgage bonds:
HELCO, 7 3/4-7 7/8%, paid in 2002		—		5,000
Obligations to the State of Hawaii for the repayment of Special Purpose Revenue Bonds:
HECO, 5.10%, series 2002A, due 2032		40,000		—
HECO, 5.70%, refunding series 2000, due 2020		46,000		46,000
MECO, 5.70%, refunding series 2000, due 2020		20,000		20,000
HECO, 6.15%, refunding series 1999D, due 2020		16,000		16,000
HELCO, 6.15%, refunding series 1999D, due 2020		3,000		3,000
MECO, 6.15%, refunding series 1999D, due 2020		1,000		1,000
HECO, 6.20%, series 1999C, due 2029		35,000		35,000
HECO, 5.75%, refunding series 1999B, due 2018		30,000		30,000
HELCO, 5.75% refunding series 1999B, due 2018		11,000		11,000
MECO, 5.75%, refunding series 1999B, due 2018		9,000		9,000
HELCO, 5.50%, refunding series 1999A, due 2014		11,400		11,400
HECO, 4.95%, refunding series 1998A, due 2012		42,580		42,580
HELCO, 4.95%, refunding series 1998A, due 2012		7,200		7,200
MECO, 4.95%, refunding series 1998A, due 2012		7,720		7,720
HECO, 5.65%, series 1997A, due 2027		50,000		50,000
HELCO, 5.65%, series 1997A, due 2027		30,000		30,000
MECO, 5.65%, series 1997A, due 2027		20,000		20,000
HECO, 5 7/8%, series 1996B, due 2026		14,000		14,000
HELCO, 5 7/8%, series 1996B, due 2026		1,000		1,000
MECO, 5 7/8%, series 1996B, due 2026		35,000		35,000
HECO, 6.20%, series 1996A, due 2026		48,000		48,000
HELCO, 6.20%, series 1996A, due 2026		7,000		7,000
MECO, 6.20%, series 1996A, due 2026		20,000		20,000
HECO, 6.60%, series 1995A, due 2025		40,000		40,000
HELCO, 6.60%, series 1995A, due 2025		5,000		5,000
MECO, 6.60%, series 1995A, due 2025		2,000		2,000
HECO, 5.45%, series 1993, due 2023		50,000		50,000
HELCO, 5.45%, series 1993, due 2023		20,000		20,000
MECO, 5.45%, series 1993, due 2023		30,000		30,000
HECO, 6.55%, series 1992, due 2022		40,000		40,000
HELCO, 6.55%, series 1992, due 2022		12,000		12,000
MECO, 6.55%, series 1992, due 2022		8,000		8,000
HELCO, 7 3/8%, series 1990C, due 2020		10,000		10,000
HELCO, 7.60%, series 1990B, due 2020		4,000		4,000
		725,900		685,900
Less funds on deposit with trustees		16,111		10,808
Total obligations to the State of Hawaii		709,789		675,092
Other long-term debt—unsecured:
HECO, 7.9% note, paid in 2002		—		9,595
Total long-term debt		709,789		689,687
Less unamortized discount		4,519		4,418
Less amounts due within one year		—		14,595
Long-term debt, net		705,270		670,674
Total capitalization	$	1,762,819	$	1,682,121

See accompanying “Notes to Consolidated Financial Statements.”

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Consolidated Statements of Cash Flows

Hawaiian Electric Company, Inc. and Subsidiaries

	Years ended December 31,
	2002			2001			2000
	(in thousands)
Cash flows from operating activities:
Income before preferred stock dividends of HECO	$	91,285		$	89,380		$	88,366
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Depreciation of utility plant		105,424			100,714			98,517
Other amortization		11,376			12,740			8,808
Deferred income taxes		12,818			8,557			5,961
Tax credits, net		1,031			2,476			982
Allowance for equity funds used during construction		(3,954	)		(4,239	)		(5,380	)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable		(4,802	)		9,448			(23,032	)
Decrease (increase) in accrued unbilled revenues		(7,475	)		11,397			(10,190	)
Decrease (increase) in fuel oil stock		(11,209	)		12,684			(2,170	)
Decrease (increase) in materials and supplies		252			(2,915	)		3,259
Increase in regulatory assets, net		(1,881	)		(4,036	)		(5,748	)
Increase (decrease) in accounts payable		6,026			(17,732	)		19,582
Increase (decrease) in taxes accrued		(6,925	)		7,872			11,651
Other		(20,389	)		(27,597	)		(21,160	)
Net cash provided by operating activities		171,577			198,749			169,446
Cash flows from investing activities:
Capital expenditures		(114,558	)		(115,540	)		(130,089	)
Contributions in aid of construction		11,042			10,958			8,484
Proceeds from sales of assets		56			—			—
Payments on notes receivable		—			—			138
Net cash used in investing activities		(103,460	)		(104,582	)		(121,467	)
Cash flows from financing activities:
Common stock dividends		(44,143	)		(36,309	)		(68,522	)
Preferred stock dividends		(1,080	)		(1,080	)		(1,080	)
Preferred securities distributions of trust subsidiaries		(7,675	)		(7,675	)		(7,675	)
Proceeds from issuance of long-term debt		35,275			17,336			87,507
Repayment of long-term debt		(5,000	)		—			(66,000	)
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		(42,697	)		(61,869	)		3,153
Proceeds from other short-term borrowings		—			—			57,499
Repayment of other short-term borrowings		—			(3,000	)		(55,682	)
Other		(2,929	)		(1,246	)		2,389
Net cash used in financing activities		(68,249	)		(93,843	)		(48,411	)
Net increase (decrease) in cash and equivalents		(132	)		324			(432	)
Cash and equivalents, January 1		1,858			1,534			1,966
Cash and equivalents, December 31	$	1,726		$	1,858		$	1,534

See accompanying “Notes to Consolidated Financial Statements.”

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Notes to Consolidated Financial Statements

Hawaiian Electric Company, Inc. and Subsidiaries

1. Summary of significant accounting policies

General

Hawaiian Electric Company, Inc. (HECO) is engaged in the business of generating, purchasing, transmitting, distributing and selling electric energy on the island of Oahu and, through its two electric utility subsidiaries, Hawaii Electric Light Company, Inc. (HELCO) on the island of Hawaii, and Maui Electric Company, Limited (MECO) on the islands of Maui, Lanai and Molokai in the State of Hawaii. At the end of 2002, HECO formed Renewable Hawaii, Inc., which is expected to invest in renewable energy projects.

Basis of presentation

In preparing the consolidated financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. Actual results could differ significantly from those estimates.

Material estimates that are particularly susceptible to significant change include the amounts reported for regulatory assets, pension and other postretirement benefit obligations, current and deferred taxes, contingencies and litigation.

Consolidation

The consolidated financial statements include the accounts of Hawaiian Electric Company, Inc. (HECO) and its subsidiaries (collectively, the Company). The Company is a wholly-owned subsidiary of Hawaiian Electric Industries, Inc. (HEI). All significant intercompany accounts and transactions have been eliminated in consolidation.

Regulation by the Public Utilities Commission of the State of Hawaii (PUC)

HECO, HELCO and MECO are regulated by the PUC and account for the effects of regulation under Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.” As a result, the actions of regulators can affect the timing of recognition of revenues, expenses, assets and liabilities. Management believes HECO and its subsidiaries’ operations currently satisfy the SFAS No. 71 criteria. However, if events or circumstances should change so that those criteria are no longer satisfied, management believes that a material adverse effect on the Company’s financial statements may result as regulatory assets would be charged to expense.

Utility plant

Utility plant is reported at cost. Self-constructed plant includes engineering, supervision, and administrative and general costs, and an allowance for the cost of funds used during the construction period. These costs are recorded in construction in progress and are transferred to utility plant when construction is completed and the facilities are either placed in service or become useful for public utility purposes. Upon the retirement or sale of electric utility plant, no gain or loss is recognized. The cost of the plant retired or sold and the cost of removal (net of salvage value) previously provided through depreciation are charged to accumulated depreciation.

Depreciation

Depreciation is computed primarily using the straight-line method over the estimated useful lives of the assets being depreciated. Electric utility plant has useful lives ranging from 20 to 45 years for production plant, from 25 to 50 years for transmission and distribution plant and from 8 to 45 years for general plant. The composite annual depreciation rate was 3.9% in 2002, 2001 and 2000.

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Cash and equivalents

The Company considers cash on hand, deposits in banks, money market accounts, certificates of deposit, short-term commercial paper and liquid investments (with original maturities of three months or less) to be cash and equivalents.

Accounts receivable

Accounts receivable are recorded at the invoiced amount. The Company assesses a late payment charge on balances unpaid from the previous month. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts receivable. The Company adjusts its allowance on a monthly basis, based on its historical write-off experience. Account balances are charged off against the allowance after collection efforts have been exhausted and the potential for recovery is considered remote.

Retirement benefits

Pension and other postretirement benefit costs/(returns) are charged/(credited) primarily to expense and electric utility plant. The Company’s policy is to fund pension costs in amounts consistent with the requirements of the Employee Retirement Income Security Act of 1974. Certain health care and/or life insurance benefits are provided to eligible retired employees and the employees’ beneficiaries and covered dependents.

Financing costs

The Company uses the straight line method to amortize financing costs and premiums or discounts over the term of the related long-term debt. Unamortized financing costs and discounts or premiums on long-term debt retired prior to maturity are classified as regulatory assets or liabilities and are amortized on a straight line basis over the remaining original term of the retired debt. The methods and periods for amortizing financing costs, premiums and discounts, including the treatment of these items when long-term debt is retired prior to maturity, have been established by the PUC as part of the rate-making process.

Contributions in aid of construction

The Company receives contributions from customers for special construction requirements. As directed by the PUC, the Company amortizes contributions on a straight-line basis over 30 years as an offset against depreciation expense.

Electric utility revenues

Electric utility revenues are based on rates authorized by the PUC and include revenues applicable to energy consumed in the accounting period but not yet billed to the customers. Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers for billing purposes is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on the following month meter readings, monthly generation volumes, estimated customer usage by account, line losses and applicable customer rates based on historical values and current rate schedules. At December 31, 2002, customer accounts receivable include unbilled energy revenues of $60 million on a base of annual revenue of $1.3 billion. Revenue amounts recorded pursuant to a PUC interim order are subject to refund, with interest, pending a final order.

The rate schedules of HECO, HELCO and MECO include energy cost adjustment (ECA) clauses under which electric rates are adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power.

The Company’s operating revenues include amounts for various revenue taxes the electric utilities collect from customers and pay to taxing authorities. Revenue taxes to be paid to the taxing authorities are recorded as an expense and a corresponding liability in the year the related revenues are recognized. Payments to the taxing authorities are made in the subsequent year. For 2002, the Company included $111 million of revenue taxes in “operating revenues” and $113 million (including a $2 million nonrecurring PUC fee adjustment) of revenue taxes

30

in “taxes, other than income taxes” expense. For 2001 and 2000, the Company included $114 million and $112 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

Allowance for Funds Used During Construction (AFUDC)

AFUDC is an accounting practice whereby the costs of debt (AFUDC-Debt) and equity (AFUDC-Equity) funds used to finance plant construction are credited on the statement of income and charged to construction in progress on the balance sheet.

The weighted-average AFUDC rate was 8.7% in 2002 and 2001 and 8.6% in 2000, and reflected quarterly compounding.

Environmental expenditures

The Company is subject to numerous federal and state environmental statutes and regulations. In general, environmental contamination treatment costs are charged to expense, unless it is probable that the PUC would allow such costs to be recovered in future rates, in which case such costs would be capitalized as regulatory assets. Also, environmental costs are capitalized if the costs extend the life, increase the capacity, or improve the safety or efficiency of property; the costs mitigate or prevent future environmental contamination; or the costs are incurred in preparing the property for sale. Environmental costs are either capitalized or charged to expense when environmental assessments and/or remedial efforts are probable and the cost can be reasonably estimated.

Income taxes

The Company is included in the consolidated income tax returns of HECO’s parent, HEI. Income tax expense has been computed for financial statement purposes as if HECO and its subsidiaries filed separate consolidated HECO income tax returns.

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

Federal and state tax investment credits are deferred and amortized over the estimated useful lives of the properties which qualified for the credits.

Governmental tax authorities could challenge a tax return position taken by management. If the Company’s position does not prevail, the Company’s results of operations and financial condition may be adversely affected as the related deferred or current income tax asset would be impaired and written down or written off.

Derivative instruments and hedging activities

Derivatives are recognized at fair value in the balance sheet as an asset or liability. Changes in fair value of derivative instruments not designated as hedging instruments are (and the ineffective portions of hedges, if any in the future, would be) recognized in earnings in the current period. In the future, any changes in the fair value of a derivative designated as a fair value hedge and the hedged item would be recorded in earnings. Also, for a derivative designated as a cash flow hedge, the effective portion of changes in fair value of the derivative would be reported in other comprehensive income and subsequently would be reclassified into earnings when the hedged item affects earnings.

Impairment of long-lived assets and long-lived assets to be disposed of

The Company reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell.

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Recent accounting pronouncements and interpretations

Asset retirement obligations. In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs would be capitalized as part of the carrying amount of the long-lived asset and depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for other than the carrying amount of the liability, the Company will recognize the difference as a regulatory asset or liability, as the provisions of SFAS No. 143 have no income statement impact for a regulated entity as long as the recovery of the regulatory asset or payment of the regulatory liability is probable. The Company adopted SFAS No. 143 on January 1, 2003 with no effect on the Company’s financial statements.

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

Costs associated with exit or disposal activities. In July 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. Examples of costs covered by the standard include lease termination costs and certain employee severance costs that are associated with a restructuring, discontinued operation, plant closing, or other exit or disposal activity. Previous accounting guidance was provided by Emerging Issues Task Force (EITF) Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” SFAS No. 146 replaces EITF Issue No. 94-3. The Company adopted the provisions of SFAS No. 146 on January 1, 2003. Since SFAS No. 146 applies prospectively to exit or disposal activities initiated after December 31, 2002, the adoption of SFAS No. 146 had no effect on the Company’s historical financial statements.

Guarantor’s accounting and disclosure requirements for guarantees. In November 2002, the FASB issued Interpretation (FIN) No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” which elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements for periods ending after December 15, 2002 about its obligations under guarantees it has issued. FIN No. 45 also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken. The Company adopted the provisions of FIN No. 45 on January 1, 2003. Since the initial recognition and measurement provisions of FIN No. 45 are applied prospectively to guarantees issued or modified after December 31, 2002, the adoption of these provisions of FIN No. 45 had no effect on the Company’s historical financial statements.

Consolidation of variable interest entities. In January 2003, the FASB issued FIN No. 46, “Consolidation of Variable Interest Entities,” which addresses the consolidation of variable interest entities (VIEs) as defined. FIN No. 46 applies immediately to variable interests in VIEs created after January 31, 2003, and to variable interests in VIEs obtained after January 31, 2003. For a variable interest in a VIE created before February 1, 2003, FIN No. 46 is applied to the enterprise no later than the beginning of the first interim or annual reporting period beginning after

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June 15, 2003. The application of FIN No. 46 is not expected to have a material effect on the Company’s financial statements.

Reclassifications

Certain reclassifications have been made to prior years’ financial statements to conform to the 2002 presentation.

2. Cumulative preferred stock

The following series of cumulative preferred stock are redeemable only at the option of the respective company and are subject to voluntary liquidation provisions as follows:

Series	Voluntary Liquidation Price December 31, 2002		Redemption Price December 31, 2002
C, D, E, H, J and K (HECO)	$	20.00	$	21.00
I (HECO)		20.00		20.00
G (HELCO)		100.00		—
H (MECO)		100.00		—

HELCO’s series G and MECO’s series H preferred stock may not be redeemed by the respective subsidiary prior to December 2003.

HECO is obligated to make dividend, redemption and liquidation payments on the preferred stock of either of its subsidiaries if the respective subsidiary is unable to make such payments, but such obligation is subordinated to any obligation to make payments on HECO’s own preferred stock.

3. HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO and HECO-guaranteed debentures

	December 31
	2002		2001		Liquidation value per security
	(in thousands, except per security amounts and number of securities)
HECO Capital Trust I* 8.05% Cumulative Quarterly Income Preferred Securities, Series 1997 (2,000,000 securities)**	$	50,000	$	50,000	$	25
HECO Capital Trust II* 7.30% Cumulative Quarterly Income Preferred Securities, Series 1998 (2,000,000 securities)***		50,000		50,000		25
	$	100,000	$	100,000

* Delaware grantor trust.

** Mandatorily redeemable at the maturity of the underlying debt on March 27, 2027, which maturity may be extended to no later than March 27, 2046. Also, redeemable at the issuer’s option after March 27, 2002.

*** Mandatorily redeemable at the maturity of the underlying debt on December 15, 2028, which maturity may be extended to no later than December 15, 2047. Also, redeemable at the issuer’s option after December 15, 2003.

In March 1997, HECO Capital Trust I (Trust I), a grantor trust which is a subsidiary of HECO, sold (i) in a public offering, 2 million of its HECO-Obligated 8.05% Cumulative Quarterly Income Preferred Securities, Series 1997 (1997 trust preferred securities) with an aggregate liquidation preference of $50 million and (ii) to HECO, common securities with a liquidation preference of approximately $1.55 million. Proceeds from the sale of the 1997 trust preferred securities and the common securities were used by Trust I to purchase 8.05% Junior Subordinated Deferrable Interest Debentures, Series 1997 (1997 junior deferrable debentures) issued by HECO in the principal amount of $31.55 million and issued by each of MECO and HELCO in the respective principal amounts of $10 million. The 1997 junior deferrable debentures, which bear interest at 8.05% and mature on March 27, 2027, together with the subsidiary guarantees (pursuant to which the obligations of MECO and HELCO under their respective debentures are fully and unconditionally guaranteed by HECO), are the sole assets of Trust I. The 1997 trust preferred securities must be redeemed at the maturity of the underlying debt on March 27,

33

2027, which maturity may be shortened to a date no earlier than March 27, 2002 or extended to a date no later than March 27, 2046, and are not redeemable at the option of the holders, but may be redeemed by Trust I, in whole or in part, from time to time, on or after March 27, 2002 or upon the occurrence of certain events. All of the proceeds from the sale were invested by Trust I in the underlying debt securities of HECO, HELCO and MECO.

In December 1998, HECO Capital Trust II (Trust II), a grantor trust which is a subsidiary of HECO, sold (i) in a public offering, 2 million of its HECO-Obligated 7.30% Cumulative Quarterly Income Preferred Securities, Series 1998 (1998 trust preferred securities) with an aggregate liquidation preference of $50 million and (ii) to HECO, common securities with a liquidation preference of approximately $1.55 million. Proceeds from the sale of the 1998 trust preferred securities and the common securities were used by Trust II to purchase 7.30% Junior Subordinated Deferrable Interest Debentures, Series 1998 (1998 junior deferrable debentures) issued by HECO in the principal amount of $31.55 million and issued by each of MECO and HELCO in the respective principal amounts of $10 million. The 1998 junior deferrable debentures, which bear interest at 7.30% and mature on December 15, 2028, together with the subsidiary guarantees (pursuant to which the obligations of MECO and HELCO under their respective debentures are fully and unconditionally guaranteed by HECO), are the sole assets of Trust II. The 1998 trust preferred securities must be redeemed at the maturity of the underlying debt on December 15, 2028, which maturity may be shortened to a date no earlier than December 15, 2003 or extended to a date no later than December 15, 2047, and are not redeemable at the option of the holders, but may be redeemed by Trust II, in whole or in part, from time to time, on or after December 15, 2003 or upon the occurrence of certain events. All of the proceeds from the sale were invested by Trust II in the underlying debt securities of HECO, HELCO and MECO.

Contractual arrangements (the “Back-up Undertakings”) entered into by HECO in connection with the issuance of the 1997 and 1998 trust preferred securities, considered together, constitute a full and unconditional guarantee by HECO, on a subordinated basis, of the periodic distributions due on the 1997 and 1998 trust preferred securities and of amounts due upon the redemption thereof or upon liquidation of the Trusts. The Back-up Undertakings include HECO’s (i) guarantee that the Trusts will make their respective periodic distributions and redemption and liquidation payments to the extent the Trusts have funds available therefore, (ii) the subsidiary guarantees, (iii) obligations under an agreement to pay all expenses and liabilities of the Trusts (other than the obligation of the Trusts to pay amounts due to the holders of the 1997 and 1998 trust preferred securities) and (iv) obligations under the trust agreements, HECO’s 1997 and 1998 junior subordinated debentures and the respective indentures pursuant to which the 1997 and 1998 junior subordinated debentures were issued. The 1997 and 1998 junior deferrable debentures and the common securities of the Trusts have been eliminated in HECO’s consolidated balance sheets as of December 31, 2002 and 2001. The 1997 and 1998 junior deferrable debentures are redeemable only (i) at the option of HECO, MECO and HELCO, respectively, in whole or in part, on or after March 27, 2002 (1997 junior deferrable debentures) and December 15, 2003 (1998 junior deferrable debentures) or (ii) at the option of HECO, in whole, upon the occurrence of a “Special Event” (relating to certain changes in laws or regulations).

4. Long-term debt

The first mortgage bonds of HELCO were secured by a mortgage which purported to be a lien on substantially all of the real and personal property owned or acquired by HELCO. The remaining two series of these bonds were redeemed in early 2002 and the mortgage was released.

For special purpose revenue bonds, the funds on deposit with trustees represent the undrawn proceeds from the issuance of the special purpose revenue bonds and earn interest at market rates. These funds are available only to pay (or reimburse payment of) expenditures in connection with certain authorized construction projects and certain expenses related to the bonds.

In September 2002, the Department of Budget and Finance of the State of Hawaii issued tax-exempt special purpose revenue bonds in the principal amount of $40 million with a maturity of 30 years and a fixed coupon interest rate of 5.10%, and loaned the proceeds from the sale to HECO.

At December 31, 2002, the aggregate payments of principal required on long-term debt during the next five years are nil in each year.

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In January 2003, MECO’s proportionate share of the 6.55% Series 1992 Special Purpose Revenue Bonds, in the principal amount of $8.0 million, was called for redemption on March 12, 2003.

5. Short-term borrowings

There were no short-term borrowings from nonaffiliates at December 31, 2002 or 2001.

At December 31, 2002 and 2001, the Company maintained bank lines of credit which totaled $100 million ($20 million maturing in March 2003, $30 million maturing in April 2003, $10 million maturing in May 2003 and $40 million maturing in June 2003) and $110 million, respectively. On January 1, 2003, HECO reduced its total lines of credit to $90 million, thereby reducing to $30 million the lines maturing in June 2003. The Company maintains lines of credit to support the issuance of commercial paper and for other general corporate purposes. None of the lines are secured. There were no borrowings under any line of credit at December 31, 2002 or during 2002. The Company borrowed and repaid $8.8 million under a line of credit in 2001.

6. Regulatory assets

In accordance with SFAS No. 71, the Company’s consolidated financial statements reflect assets and costs based on current cost-based rate-making regulations. Continued accounting under SFAS No. 71 requires that certain criteria be met. Management believes the Company’s operations currently satisfy the criteria. However, if events or circumstances change so that the criteria are no longer satisfied, management believes that a material adverse effect on the Company’s financial statements may result as the regulatory assets would be charged to expense.

Regulatory assets are expected to be fully recovered through rates over PUC authorized periods ranging from one to 36 years (periods noted in parenthesis) and include the following deferred costs:

	December 31,
	2002		2001
	(in thousands)
Income taxes (1 to 36 years)	$	64,278	$	62,467
Postretirement benefits other than pensions (10 years)		17,897		19,687
Unamortized expense and premiums on retired debt and equity issuances (2 to 26 years)		11,005		12,100
Integrated resource planning costs (1 year)		1,965		6,243
Vacation earned, but not yet taken (1 year)		4,776		4,929
Other (1 to 4 years)		5,647		5,950
	$	105,568	$	111,376

Regulatory asset related to Barbers Point Tank Farm project costs

In December 1991, HECO filed an application with the PUC for the installation of a nominal 200 megawatt (MW) combined cycle power plant. Due to changes in circumstances, the expected timing for HECO’s next generating unit was significantly delayed, and HECO withdrew its application in May 1993. In August 1994, HECO informed the PUC that, consistent with past and current company practices, the accumulated project costs would be allocated primarily to ongoing active capital projects. The PUC advised HECO to file an application, which it did in February 1995, citing project costs of $5.8 million. The Consumer Advocate objected to the accounting treatment proposed by HECO. To simplify and expedite the proceeding, in September 2000, HECO and the Consumer Advocate reached an agreement on the accounting treatment, subject to PUC approval. Acceptance of the agreement by the parties was without prejudice to any position either of them may take in any subsequent proceeding. Under the agreement, $4.5 million of the $5.8 million total project costs would be amortized to operating expense ratably over a five-year period. In September 2000, HECO adjusted the project costs by $1.3 million to reflect the agreement with the Consumer Advocate, resulting in an after tax write-off of $0.8 million. In September 2001, HECO received PUC approval to amortize $4.5 million over a five-year period, which HECO began in October 2001.

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Integrated Resource Planning costs

In 1992, the PUC established a framework for Integrated Resource Planning (IRP) and ordered the companies to develop an integrated resource plan in accordance with the IRP framework. The framework also provides that the utilities are entitled to recover appropriate IRP and implementation costs. Each year, HECO, HELCO and MECO submit a budget of the IRP costs for the upcoming year, and request subsequent recovery of the actual costs incurred. Actual IRP costs incurred since 1995 have been recorded as a regulatory asset, and are charged to expense as the Company recovers those costs through rates.

The PUC has allowed the Company to recover IRP costs pending the PUC’s final decision and order approving recovery of each respective year’s IRP costs. Recovery of IRP costs is subject to refund with interest. HECO has been allowed and has fully recovered its deferred IRP costs for years 1995 through 2001. MECO has been allowed to recover its deferred IRP costs for years 1995 through 2001, and is currently recovering costs incurred for year 2001. HELCO has been allowed and has fully recovered its deferred IRP costs for years 1995 through 2000. HELCO’s costs for year 2001 and subsequent years are included in its base rates. As of December 31, 2002, the amount of revenues recorded, subject to refund with interest, amounted to $16.0 million.

7. Income taxes

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

	December 31,
	2002			2001			2000
	(in thousands)
Federal:
Current	$	37,481		$	41,120		$	43,206
Deferred		13,337			8,584			6,243
Deferred tax credits, net		(1,557	)		(1,567	)		(1,585	)
		49,261			48,137			47,864
State:
Current		5,369			3,272			5,446
Deferred		1,068			1,549			921
Deferred tax credits, net		1,031			2,476			982
		7,468			7,297			7,349
Total	$	56,729		$	55,434		$	55,213

Income tax benefits related to nonoperating activities, included in “Other, net” on the consolidated statements of income, amounted to $71,000, $18,000 and $162,000 for 2002, 2001 and 2000, respectively.

A reconciliation between income taxes charged to operating expenses and the amount of income taxes computed at the federal statutory rate of 35% on income before income taxes and preferred stock dividends follows:

	December 31,
	2002			2001			2000
	(in thousands)
Amount at the federal statutory income tax rate	$	52,226		$	51,005		$	50,573
State income taxes on operating income, net of effect on federal income taxes		4,854			4,743			4,777
Other		(351	)		(314	)		(137	)
Income taxes charged to operating expenses	$	56,729		$	55,434		$	55,213

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

	December 31,
	2002		2001
	(in thousands)
Deferred tax assets:
Property, plant and equipment	$	12,801	$	12,488
Contributions in aid of construction and customer advances		46,052		47,546
Other		13,213		12,382
		72,066		72,416
Deferred tax liabilities:
Property, plant and equipment		174,832		170,559
Regulatory assets		24,794		24,313
Other		30,807		23,152
		230,433		218,024
Net deferred income tax liability	$	158,367	$	145,608

The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Based upon historical taxable income, projections for future taxable income and tax planning strategies, management believes it is more likely than not the Company will realize the benefits of the deferred tax assets and has provided no valuation allowance for deferred tax assets during 2002, 2001 and 2000.

8. Cash flows

Supplemental disclosures of cash flow information

Cash paid during 2002, 2001 and 2000 for interest (net of AFUDC-Debt) and income taxes was as follows:

	December 31,
	2002		2001		2000
	(in thousands)
Interest	$	45,230	$	43,519	$	44,020
Income taxes	$	47,530	$	38,392	$	56,875

Supplemental disclosures of noncash activities

The allowance for equity funds used during construction, which was charged primarily to construction in progress, amounted to $4.0 million, $4.2 million and $5.4 million in 2002, 2001 and 2000, respectively.

The estimated fair value of noncash contributions in aid of construction amounted to $4.4 million, $2.4 million and $6.6 million in 2002, 2001 and 2000, respectively.

In 2002, HECO assigned accounts receivable totaling $10.5 million to a creditor, without recourse, in full settlement of HECO’s $10.5 million notes payable to the creditor.

9. Major customers

HECO and its subsidiaries derived approximately 9% of their operating revenues from the sale of electricity to various federal government agencies in 2002 and 10% in 2001 and 2000. These revenues amounted to $119 million in 2002, $127 million in 2001 and $123 million in 2000.

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10. Retirement benefits

Pensions

Substantially all of the employees of the Company participate in the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries (Plan). The Plan is a qualified, non-contributory defined benefit pension plan with the benefits for union employees determined in accordance with the terms of the collective bargaining agreements between the Company and their respective unions. The Plan is subject to the provisions of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In addition, some current and former executives and directors of the Company participate in noncontributory, nonqualified plans (collectively, Supplemental/Excess/Directors Plans). In general, benefits are based on the employees’ years of service and compensation.

The Plan and the Supplemental/Excess/Directors Plans were adopted with the expectation that they will continue indefinitely, but the continuation of these plans and the payment of any contribution thereunder is not assumed as a contractual obligation by the participating employers. Each participating employer reserves the right to terminate its participation in the applicable plan at any time, and HEI reserves the right to terminate its respective plan at any time. If a participating employer terminated its participation in the Plan, the interest of each affected participant would become 100% vested to the extent funded. Upon the termination of the Plan, assets would be distributed to affected participants in accordance with the applicable allocation provisions of ERISA and any excess assets that exist would be paid to the Participating Employers. Participants’ benefits are covered up to certain limits under insurance provided by the Pension Benefit Guaranty Corporation (PBGC).

The Participating Employers contribute amounts to a master pension trust (Trust) for the Plan in accordance with the funding requirements of ERISA and considering the deductibility of contributions under the Internal Revenue Code (Code). The funding of the Plan is based on actuarial assumptions adopted by the Pension Investment Committee administering the Plan on the advice of an enrolled actuary.

To determine pension costs for the Company under the Plan and the supplemental/Excess/Directors Plans, it is necessary to make complex calculations and estimates based on numerous assumptions, including the weighted-average assumptions identified below.

Postretirement benefits other than pensions

The Company provides eligible employees health and life insurance benefits upon retirement under the Postretirement Welfare Benefits Plan for Employees of Hawaiian Electric Company, Inc. and Participating Employers. The amount of health benefits is based on retirees’ years of service and retirement date. Generally, employees are eligible for these benefits if, upon retirement, they participate in the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries.

The postretirement benefits plan was adopted with the expectation that it will continue indefinitely, but the continuation of the plan and the payment of any contribution thereunder is not assumed as a contractual obligation by the participating employers. Each participating employer reserves the right to terminate its participation in the postretirement benefits plan at any time.

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Pension and other postretirement benefit plans information

The changes in the pension and other postretirement benefit defined benefit plans’ obligations and plan assets, the funded status of the plans and the unrecognized and recognized amounts reflected in the balance sheet were as follows:

	Pension benefits						Other benefits
	2002			2001			2002			2001
	(in thousands)
Benefit obligation, January 1	$	591,036		$	552,030		$	143,055		$	122,161
Service cost		16,965			16,317			3,028			2,951
Interest cost		41,891			40,073			9,920			9,128
Amendments		—			(217	)		—			—
Actuarial loss		46,578			15,170			6,004			15,344
Benefits paid		(34,181	)		(32,337	)		(6,369	)		(6,529	)
Benefit obligation, December 31		662,289			591,036			155,638			143,055
Fair value of plan assets, January 1		677,590			788,955			88,448			102,265
Actual loss on plan assets		(91,778	)		(79,291	)		(13,927	)		(11,264	)
Employer contribution		328			242			6,382			3,976
Benefits paid		(34,173	)		(32,316	)		(6,369	)		(6,529	)
Fair value of plan assets, December 31		551,967			677,590			74,534			88,448
Funded status		(110,322	)		86,554			(81,104	)		(54,607	)
Unrecognized net actuarial loss (gain)		185,270			(32,930	)		23,604			(6,915	)
Unrecognized net transition obligation		960			3,223			32,642			35,907
Unrecognized prior service gain		(8,031	)		(8,781	)		—			—
Net amount recognized, December 31	$	67,877		$	48,066		$	(24,858	)	$	(25,615	)
Amounts recognized in the balance sheet consist of:
Prepaid benefit cost	$	70,635		$	50,817		$	—		$	—
Accrued benefit liability		(2,758	)		(2,751	)		(24,858	)		(25,615	)
Net amount recognized, December 31	$	67,877		$	48,066		$	(24,858	)	$	(25,615	)

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

	Pension benefits						Other benefits
	December 31,
	2002		2001		2000		2002		2001		2000
Discount rate	6.75	%	7.25	%	7.50	%	6.75	%	7.25	%	7.50	%
Expected return on plan assets	9.0		10.0		10.0		9.0		10.0		10.0
Rate of compensation increase	4.6		4.6		4.6		4.6		4.6		4.6

At December 31, 2002, the assumed health care trend rates for 2003 and future years were as follows: medical, 9.28%, grading down to 4.25%; dental, 4.25%; and vision, 3.25%. At December 31, 2001, the assumed health care trend rates for 2002 and future years were as follows: medical, 10.00%, grading down to 4.75%; dental, 4.75%; and vision, 3.75%.

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

	Pension benefits									Other benefits
	2002			2001			2000			2002			2001			2000
	(in thousands)
Service cost	$	16,965		$	16,317		$	15,385		$	3,028		$	2,951		$	2,737
Interest cost		41,891			40,073			38,526			9,920			9,128			8,742
Expected return on plan assets		(76,169	)		(75,644	)		(70,460	)		(9,872	)		(9,882	)		(9,189	)
Amortization of unrecognized transition obligation		2,263			2,273			2,273			3,264			3,264			3,264
Amortization of prior service gain		(750	)		(750	)		(703	)		—			—			—
Recognized actuarial gain		(3,683	)		(8,210	)		(9,398	)		(716	)		(2,597	)		(3,112	)
Net periodic benefit cost (return)	$	(19,483	)	$	(25,941	)	$	(24,377	)	$	5,624		$	2,864		$	2,442

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Of the net periodic pension benefit costs (returns), the Company recorded income of approximately $14.3 million in 2002, $19.0 million in 2001 and $18.2 million in 2000, respectively, and credited the remaining amounts primarily to electric utility plant. Of the net periodic other benefit costs, the Company expensed $4.1 million, $2.1 million and $1.8 million in 2002, 2001 and 2000, respectively, and charged the remaining amounts primarily to electric utility plant.

At December 31, 2002 and 2001, the Company had pension plans in which the accumulated benefit obligations exceeded plan assets at fair value, but such plans did not have material benefit obligations.

The health care cost trend rate assumptions can have a significant effect on the amounts reported for other benefits. At December 31, 2002, a one-percentage-point increase in the assumed health care cost trend rates would have increased the total service and interest cost by $0.3 million and the postretirement benefit obligation by $3.7 million, and a one-percentage-point decrease would have reduced the total service and interest cost by $0.3 million and the postretirement benefit obligation by $4.4 million.

11. Commitments and contingencies

Fuel contracts

The Company has contractual agreements to purchase minimum quantities of fuel oil and diesel fuel through 2004 (at prices tied to the market prices of petroleum products in Singapore and Los Angeles). Based on the average price per barrel at January 1, 2003, the estimated cost of minimum purchases under the fuel supply contracts for 2003 is $329 million. The actual cost of purchases in 2003 could vary substantially from this estimate as a result of changes in market prices, quantities actually purchased and/or other factors. The Company purchased $317 million, $328 million and $359 million of fuel under contractual agreements in 2002, 2001 and 2000, respectively.

Power purchase agreements

At December 31, 2002, the Company had power purchase agreements for 534 MW of firm capacity. The PUC allows rate recovery for energy and firm capacity payments under these agreements. Assuming that each of the agreements remains in place for its current term and the minimum availability criteria in the power purchase agreements are met, aggregate minimum fixed capacity charges are expected to be approximately $123 million each in 2003 and 2004, $118 million each in 2005, 2006 and 2007 and a total of $1.6 billion in the period from 2008 through 2030.

In general, the Company bases its payments under the power purchase agreements upon available capacity and energy and is generally not required to make payments for capacity if the contracted capacity is not available, and payments are reduced, under certain conditions, if available capacity drops below contracted levels. In general, the payment rates for capacity have been predetermined for the terms of the agreements. Energy payments will vary over the terms of the agreements and the Company passes on changes in the fuel component of the energy charges to customers through the ECA clause in the rate schedules. The Company does not operate nor participate in the operation of any of the facilities that provide power under the agreements. Title to the facilities does not pass to the Company upon expiration of the agreements, and the agreements do not contain bargain purchase options for the facilities.

Interim increases

At December 31, 2002, HECO and its electric utility subsidiaries recognized $16.0 million of revenues with respect to interim orders regarding certain integrated resource planning costs, which revenues are subject to refund, with interest, if and to the extent they exceed the amounts allowed in final orders.

HELCO power situation

In 1991, HELCO began planning to meet increased electric generation demand forecasted for 1994. HELCO’s plans were to install at its Keahole power plant two 20 MW combustion turbines (CT-4 and CT-5), followed by an 18 MW heat steam recovery generator (ST-7), at which time these units would be converted to a 56 MW (net) dual-train combined-cycle unit. In January 1994, the PUC approved expenditures for CT-4, which HELCO had planned to install in late 1994. In 1995, the PUC allowed HELCO to pursue construction of and commit expenditures for CT-5 and ST-7, but noted that such costs are not to be included in rate base until the project is

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installed and “is used and useful for utility purposes.” The PUC at that time also ordered HELCO to continue negotiating with independent power producers (IPPs), stating that the facility to be built should be the one that can be most expeditiously put into service at “allowable cost.”

The timing of the installation of HELCO’s phased units has been revised on several occasions due to delays in obtaining an amendment of a land use permit from the Hawaii Board of Land and Natural Resources (BLNR) and an air permit from the Department of Health of the State of Hawaii (DOH) and the U.S. Environmental Protection Agency (EPA) for the Keahole power plant site. The delays are also attributable to lawsuits, claims and petitions filed by IPPs and other parties challenging these permits and objecting to the expansion, alleging among other things that (1) operation of the expanded Keahole site would not comply with land use regulations (including noise standards) and HELCO’s land patent; (2) HELCO cannot operate the plant within current air quality standards; (3) HELCO could alternatively purchase power from IPPs to meet increased electric generation demand; and (4) HELCO’s land use entitlement expired in April 1999 because it had not completed the project within a three-year construction period.

As a result of a September 19, 2002 decision by the Third Circuit Court of the State of Hawaii (Circuit Court), relating to an extension of a construction deadline and described below under “Land use permit amendment,” the construction of CT-4 and CT-5, which had commenced in April 2002 after HELCO had obtained a final air permit and the Circuit Court had lifted a stay on construction, has been suspended. HELCO has appealed this ruling to the Hawaii Supreme Court and is considering other options that may allow HELCO to complete the installation of CT-4 and CT-5 (including seeking a land use reclassification of the Keahole site from the State Land Use Commission). If none of these options is ultimately successful, or if other permitting issues or problems arise which HELCO cannot satisfactorily resolve, HELCO may be unable to complete the installation of CT-4 and CT-5.

The following is a detailed discussion of the existing Keahole situation, including a description of its potential financial statement implications under “Management’s evaluation; costs incurred.”

Land use permit amendment. The Circuit Court ruled in 1997 that because the BLNR had failed to render a valid decision on HELCO’s application to amend its land use permit before the statutory deadline in April 1996, HELCO was entitled to use its Keahole site for the expansion project (HELCO’s “default entitlement”). Final judgments of the Circuit Court related to this ruling are on appeal to the Hawaii Supreme Court, which in 1998 denied motions to stay the Circuit Court’s final judgment pending resolution of the appeal.

The Circuit Court’s final judgment provided that HELCO must comply with the conditions in its application and with the standard land use conditions insofar as those conditions were not inconsistent with HELCO’s default entitlement. There have been numerous proceedings before the Circuit Court and the BLNR in which certain parties (a) have sought determinations of what conditions apply to HELCO’s default entitlement, (b) have claimed that HELCO has not complied with applicable land use conditions and that its default entitlement should thus be forfeited, (c) have claimed that HELCO will not be able to operate the proposed plant without violating applicable land use conditions and provisions of Hawaii’s Air Pollution Control Act and Noise Pollution Act and (d) have sought orders enjoining any further construction at the Keahole site.

Although there has not been a final resolution of these claims, there have been several significant rulings relating to these claims, some of which may adversely affect HELCO’s ability to construct and efficiently operate CT-4 and CT-5. First, based on a change by the DOH in its interpretation of the noise rules it promulgated under the Hawaii Noise Pollution Act, the Circuit Court ruled that a stricter noise standard than the previously applied standard applies to HELCO’s plant, but left enforcement of the ruling to the DOH. HELCO filed a separate complaint for declaratory relief against the DOH seeking the invalidation of the noise rules on constitutional and other grounds. The Circuit Court denied HELCO’s motion for summary judgment, finding that the noise rules are constitutional on their face but specifically not ruling on the constitutionality of the rules as applied to Keahole. HELCO appealed the final judgment to the Hawaii Supreme Court in August 1999 and a decision on that appeal is pending. The DOH has been periodically monitoring noise levels at the site. If the DOH were to issue a notice of violation based on the stricter standards, HELCO may, among other things, assert that the noise regulations, as applied to it at Keahole, are unconstitutional. Meanwhile, while not waiving possible claims or defenses that it might have against the DOH, HELCO has installed noise mitigation measures on the existing units at Keahole and, should construction be allowed to continue, is planning to implement additional noise mitigation measures for both the existing units and for CT-4 and CT-5. The estimated cost for these additional noise mitigation measures

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(for the existing units and CT-4 and CT-5) is $5 million, which would be capitalized. While the noise mitigation measures were being implemented, HELCO applied to the DOH and received approval for a noise permit through 2003, which has since been extended to July 2007.

Second, in September 2000, the Circuit Court orally ruled that, absent a legal or equitable extension properly authorized by the BLNR, the three-year construction period in the standard land use conditions of the Department of Land and Natural Resources of the State of Hawaii (DLNR) expired in April 1999. On November 9, 2000, the Circuit Court issued a written ruling to that effect. In December 2000, the Circuit Court granted a motion to stay further construction until extension of the construction deadline is obtained from the BLNR. After conducting a contested case hearing in September 2001, which resulted in the hearings officer recommending an extension be granted, the BLNR, by Order dated March 25, 2002, granted HELCO an extension of the construction deadline through December 31, 2003. The extension was subject to a number of conditions, including, but not limited to, HELCO (1) complying with all applicable laws and with all conditions applicable (a) to the default entitlement, including the 15 standard land use conditions (except where deviations are approved by the BLNR), and (b) to each Conservation District Use Permit (CDUP) and amendment previously awarded to HELCO for this site; (2) agreeing to indemnify and hold the State harmless from claims arising out of any act or omission of HELCO relating to the “permit”; (3) proceeding with construction in accordance with construction plans to be submitted to and signed by the chairperson of the BLNR; (4) obtaining approval of the DOH and the Board of Water Supply for any potable water supply or sanitation facilities; (5) complying with its representations relative to mitigation, as set forth in the accepted environmental impact statement; (6) minimizing or eliminating any interference, nuisance or harm which may be caused by this land use; (7) filing, within 90 days of the Order, an application for boundary amendment with the State Land Use Commission (LUC) to remove the site from the conservation district; and (8) complying with other terms and conditions as prescribed by the chairperson of the BLNR. The Order states that failure to comply with any of these conditions would render the “permit” void. The Order also states that “no further extensions will be provided.” In April 2002, based on this BLNR decision, the Circuit Court lifted the stay on construction in light of the BLNR’s Order, and construction activities on CT-4 and CT-5 then commenced.

Keahole Defense Coalition, Inc. (KDC) and two individuals appealed the BLNR’s March 25, 2002 Order to the Circuit Court, as did the Department of Hawaiian Home Lands. On September 19, 2002, the Circuit Court issued a letter to the parties indicating the Circuit Court’s decision to reverse the BLNR’s Order. The letter states that:

1. The BLNR exceeded its statutory authority in granting the extension of the permit. The findings do not support any authority by statute or rule.

2. The conclusions of law are erroneous.

3. The BLNR’s action in denying Appellants’ motion to subpoena a material witness regarding a letter issued by the DLNR on January 30, 1998 to HELCO (addressing the applicability of the standard land use conditions and stating that the three-year deadline did not apply) violated Appellants’ constitutional rights to a fair hearing.

4. The BLNR’s granting the extension is clearly erroneous in view of the BLNR’s Findings of Fact and Conclusions of Law.

The Circuit Court issued an Order to this effect on October 3, 2002.

On November 1, 2002, HELCO filed a notice of appeal of the October 3, 2002 Order (which appeal will be decided by the Hawaii Supreme Court or Hawaii Intermediate Court of Appeals). On November 15, 2002, HELCO also filed with the Hawaii Supreme Court a Motion for Stay Pending Disposition of Appeal and a Motion to Expedite Transmission of Record on Appeal. The Motion to Expedite was denied on December 10, 2002. The Motion for Stay was denied in early 2003. On November 25, 2002, KDC and two individuals filed with the Supreme Court a Motion to Dismiss this appeal on the basis that the case was moot, since HELCO no longer had a default entitlement because it allegedly violated the BLNR’s March 25, 2002 Order by withdrawing its application to the LUC for a boundary amendment. That motion was denied in early 2003. Accordingly, the Hawaii Supreme Court continues to assert jurisdiction over this appeal and briefs will be filed.

On November 1, 2002, HELCO filed with the Circuit Court a notice of appeal of the original November 9, 2000 ruling that the three-year deadline had expired in April 1999. In early 2003, the Supreme Court dismissed that appeal for lack of jurisdiction. The Supreme Court’s Order stated that HELCO’s appeal was not timely filed

42

because it was not filed within 30 days of the Circuit Court’s November 9, 2000 Order, even though the Circuit Court ruled at the time that its Order could not yet be appealed.

In the meantime, construction activities on CT-4 and CT-5 have been suspended and steps have been taken to secure the site and protect equipment and personnel.

Third, in other pending litigation, at a hearing on May 8, 2002, the Circuit Court denied the following motions made by KDC and others: a motion for a stay while one of the appeals is pending; a motion for injunction to enjoin construction (based on the allegation that HELCO’s default entitlement is no longer valid); and a motion for preliminary injunction to enjoin construction until the Hawaii Supreme Court decides HELCO’s appeal of the DOH noise regulations and until HELCO demonstrates that the expanded plant can satisfy the noise standards established in 1999 by the Circuit Court. On June 10, 2002, the nonprevailing parties filed a notice of appeal to the Hawaii Supreme Court of the Circuit Court’s decision denying the motion for injunction. The parties have filed briefs in that case.

Air permit. In 1997, the DOH issued a final air permit for the Keahole expansion project. Nine appeals of the issuance of the permit were filed with the EPA’s Environmental Appeals Board (EAB). In November 1998, the EAB denied the appeals on most of the grounds stated, but directed the DOH to reopen the permit for limited purposes. The EPA and DOH required additional data collection, which was satisfactorily completed in April 2000. A final air permit was reissued by the DOH in July 2001. Six appeals were filed with the EAB, but those appeals were denied. On November 27, 2001, the final air permit became effective.

Land Use Commission petition. One of the conditions of the construction period extension granted by the BLNR (which the Circuit Court’s October 3, 2002 Order now has reversed) was that HELCO file an application for a boundary amendment with the LUC to remove the site from the conservation district. HELCO filed the application on June 21, 2002. A hearing before the LUC was held on September 12, 2002, at which public testimony was taken and memoranda were received regarding the jurisdiction of the LUC in dealing with the HELCO petition. In light of subsequent events, HELCO withdrew its petition on October 3, 2002. Under LUC rules, after such a voluntary withdrawal the applicant may submit another petition for the same property one year from the date of withdrawal. HELCO intends to submit a new petition for reclassification in the fourth quarter of 2003.

IPP Complaints. Three IPPs—Kawaihae Cogeneration Partners (KCP), Enserch Development Corporation (Enserch) and Hilo Coast Power Company (HCPC)—filed separate complaints with the PUC in 1993, 1994 and 1999, respectively, alleging that they are each entitled to a power purchase agreement (PPA) to provide HELCO with additional capacity. KCP and Enserch each claimed they would be a substitute for HELCO’s planned expansion of Keahole.

The Enserch and HCPC complaints have been resolved by HELCO’s entry into two PPAs, which were necessary to ensure reliable service to customers on the island of Hawaii, but, in the opinion of management, do not supplant the need for CT-4 and CT-5. HELCO can terminate the PPA with HCPC prior to its 2004 expiration date, for a fee.

In October 1999, the Circuit Court ruled that the lease for KCP’s proposed plant site was invalid. In January 2003, the PUC issued an order denying KCP’s July 1999 request to reopen KCP’s 1993 complaint docket and to enforce the Public Utility Regulatory Policies Act of 1978. Based on these rulings and for other reasons, management believes that KCP’s proposal for a PPA is not viable and, therefore, will not impact the need for CT-4 and CT-5.

Management’s evaluation; costs incurred. In addition to the appeal of the October 3, 2002 Circuit Court’s Order filed on November 1, 2002, HELCO is considering other options that may allow HELCO to complete the installation of CT-4 and CT-5, including seeking a land use reclassification of the Keahole site from the State Land Use Commission. At this time, the likelihood of success of any of these options cannot be ascertained. Even if the Circuit Court’s Order is ultimately overturned on appeal, however, construction is likely to be further significantly delayed, and the costs to complete construction may be significantly increased, due to the time that is likely to be required to resolve the legal proceedings. In the meantime, one concern of HELCO’s management is the condition and performance of certain aging generators on the HELCO system, which were intended to be retired or to be operated less frequently once CT-4 and CT-5 were installed, as well as the current operating status of various IPPs, which provide approximately 43% of HELCO’s generating capacity. Another concern is the possibility of

43

power interruptions under exigent circumstances, including rolling blackouts, as IPPs and/or HELCO’s generating units become unavailable or less available (i.e., available at lower capacity) due to forced outages or planned maintenance. Such incidents occurred or were at risk of occurring on October 3, 2002 and November 8, 2002. As it has done on such occasions in the past, HELCO will endeavor to avert power interruptions, including rolling blackouts, in the future through a number of actions in addition to managing the generating units on its system, such as requesting customers to reduce demand during critical periods such as the peak evening hours. Under current system conditions, however, there can be no assurance that power interruptions will not occur.

The recovery of costs relating to CT-4 and CT-5 are subject to the rate-making process governed by the PUC. Management believes no adjustment to costs incurred to put CT-4 and CT-5 into service is required as of December 31, 2002. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HELCO may be required to write off a material portion of the costs incurred in its efforts to put these units into service whether or not CT-4 and CT-5 are installed. As of December 31, 2002, HELCO’s costs incurred in its efforts to put CT-4 and CT-5 into service and to support existing units (excluding costs the PUC permitted to be transferred to plant-in-service for pre-air permit facilities) amounted to approximately $82 million, including $32 million for equipment and material purchases, $30 million for planning, engineering, permitting, site development and other costs and $20 million for AFUDC. In addition to the $82 million in construction in progress, construction and/or purchase commitments related to CT-4 and CT-5 outstanding as of December 31, 2002 are estimated at approximately $0.6 million.

Although management believes it has acted prudently with respect to the Keahole project, effective December 1, 1998, HELCO discontinued the accrual of AFUDC on CT-4 and CT–5 due in part to the delays through that date and the potential for further delays. HELCO has also deferred plans for ST-7 to a date outside the near-term planning horizon. No costs for ST-7 are included in construction in progress.

Oahu transmission system

Oahu’s power sources are located primarily in West Oahu. The bulk of HECO’s system load is in the Honolulu/East Oahu area. HECO transmits bulk power to the Honolulu/East Oahu area over two major transmission corridors (Northern and Southern). HECO has for some time planned to construct a part underground/part overhead 138 kilovolt (kv) transmission line from the Kamoku substation to the Pukele substation in order to close the gap between the Southern and Northern corridors and provide a third 138 kv transmission line to the Pukele substation.

Construction of the Kamoku to Pukele transmission line in its proposed location required the BLNR to approve a CDUP for the overhead portion of the line that would have been in conservation district lands. Several community and environmental groups have opposed the project, particularly the overhead portion of the line.

In November 2000, the DLNR accepted a Revised Final Environmental Impact Statement (RFEIS) prepared in support of HECO’s application for a CDUP. In January 2001, three organizations and an individual filed a complaint against the DLNR and HECO challenging the DLNR’s acceptance of the RFEIS and seeking, among other things, a judicial declaration that the RFEIS is inadequate and null and void. HECO continues to contest the lawsuit.

The BLNR held a public hearing on the CDUP in March 2001, at which several groups requested a contested case hearing which was held in November 2001. The hearings officer submitted his report, findings of fact and conclusions of law and recommended that HECO’s request for the CDUP be denied. He concluded that HECO had failed to establish that there is a need that outweighs the transmission line’s adverse impacts on conservation district lands and that there are practical alternatives that could be pursued, including an all-underground route outside the conservation district lands. On June 28, 2002, the BLNR issued a ruling denying HECO’s request for the CDUP.

HECO continues to believe that the proposed project is needed. The project would address future potential transmission line overloads in the Northern and Southern corridors under certain contingencies (in which one of the three lines feeding power to the Koolau/Pukele area served by the Northern Corridor, or to the downtown Honolulu area served by the Southern Corridor, is out for maintenance, and a second line incurs an unexpected outage), and improves the reliability of the Pukele substation. The line overload contingencies could occur, given current load growth forecasts, in 2005 for the Northern Corridor, but not until 2013 or later in the Southern Corridor. The Pukele substation, at the end of the Northern corridor, serves approximately 18% of Oahu’s

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electrical load, including Waikiki. If one of the 138 kV transmission lines to the Pukele substation fails while the other is out for maintenance, a major system outage would result.

HECO is evaluating alternative ways to accomplish the project, and possible future actions to expedite PUC review of the alternatives (and the need for the project). Until this evaluation of alternatives is completed, an estimated project completion date cannot be determined.

As of December 31, 2002, the accumulated costs related to the Kamoku to Pukele transmission line amounted to $17 million, including $12 million for planning, engineering and permitting costs and $5 million for AFUDC. These costs are recorded in construction in progress. The recovery of costs relating to the Kamoku to Pukele transmission line is subject to the rate-making process administered by the PUC. Management believes no adjustment to project costs incurred is required as of December 31, 2002. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HECO may be required to write off a material portion or all of the project costs incurred in its efforts to put the Kamoku to Pukele transmission line into service whether or not the project is completed.

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

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

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

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

On May 22, 2002, AES, with the consent of HECO and HEI, removed the case to the U.S. District Court for the District of Hawaii (District Court) on the ground that the action arises under and is completely preempted by the Public Utility Regulatory Policies Act of 1978. On June 12, 2002, HECO and HEI filed a motion to dismiss the complaint on the grounds that the plaintiffs’ claims either arose prior to enactment of the Hawaii False Claims Act, which does not have retroactive application, or are barred by the applicable statute of limitations. AES also filed a motion to dismiss, on the same and additional grounds.

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

On December 20, 2002, HECO and HEI re-filed their motion to dismiss the complaint. AES joined in the motion. At a hearing on the motion in early 2003, the First Circuit Court ordered dismissal of the qui tam claims relating to actions prior to May 26, 2000, the effective date of the Hawaii False Claims Act, on the ground that the

45

Act did not have retroactive application. Subsequently, the First Circuit Court issued a minute order dismissing Plaintiffs’ claims for (1) violations of Hawaii’s Unfair and Deceptive Practices Act, (2) unjust enrichment/restitution and (3) fraud, which claims were purportedly brought as a class action, on the ground that all of these claims were barred by the applicable statutes of limitations.

As a result of the Circuit Court’s ruling, the only claim that appears to remain is under the Hawaii False Claims Act based on allegations that false bills or claims were submitted to the State after May 26, 2000. Under the False Claims Act, a defendant may be liable to a qui tam plaintiff for treble damages, plus civil penalties of a minimum of $5,000 for each false claim, plus attorneys’ fees and costs incurred in the action. The Plaintiffs appear to claim that each monthly bill submitted to each state agency and office on Oahu constitutes a separate false claim.

Management intends to vigorously defend the lawsuit.

Environmental regulation

In early 1995, the DOH initially advised HECO and others that it was conducting an investigation to determine the nature and extent of actual or potential releases of hazardous substances, oil, pollutants or contaminants at or near Honolulu Harbor. The DOH issued letters in December 1995 indicating that it had identified a number of parties, including HECO, who appear to be potentially responsible for the contamination and/or operated their facilities upon contaminated land. The DOH met with these identified parties in January 1996 and certain of the identified parties (including HECO, Chevron Products Company, the State of Hawaii Department of Transportation Harbors Division and others) formed a Honolulu Harbor Work Group (Work Group). Effective January 30, 1998, the Work Group and the DOH entered into a voluntary agreement and scope of work to determine the nature and extent of any contamination, the potentially responsible parties and appropriate remedial actions.

In 1999, the Work Group submitted reports to the DOH presenting environmental conditions and recommendations for additional data gathering to allow for an assessment of the need for risk-based corrective action. The Work Group also engaged a consultant who identified 27 additional potentially responsible parties (PRPs) who were not members of the Work Group.

In response to the DOH’s request for technical assistance, the EPA became involved with the harbor investigation in June 2000. In November 2000, the DOH issued notices to over 20 other PRPs regarding the ongoing investigation in the Honolulu Harbor area. A new voluntary agreement and a joint defense agreement were signed by the parties in the Work Group and some of the new PRPs, including Phillips Petroleum. The group is now called the Iwilei District Participating Parties (Participating Parties). The Participating Parties agreed to fund remediation work using an interim cost allocation method.

In July 2001, the EPA issued a notice of interest (Initial NOI) under the Oil Pollution Act of 1990 to HECO and others regarding the Iwilei Unit of the Honolulu Harbor site. In the Initial NOI, the EPA stated that immediate subsurface investigation and assessment (also known as Rapid Assessment Work) must be conducted to delineate the extent of contamination at the site. The Participating Parties completed the Rapid Assessment Work, submitted a report to the EPA and DOH in January 2002, and developed a proposal for additional investigation (known as the Phase 2 Rapid Assessment Work), which the EPA and DOH approved. The Participating Parties substantially completed the Phase 2 Rapid Assessment Work in the third quarter of 2002 and are currently performing a data validation study of the data collected, after which they anticipate submitting a report to EPA and DOH in the second quarter of 2003.

In September 2001, the EPA and DOH concurrently issued notices of interest (collectively, the Second NOI) to the members of the Participating Parties, including HECO. The Second NOI identified several investigative and preliminary oil removal tasks to be taken at certain valve control facilities associated with historic pipelines in the Iwilei Unit of the Honolulu Harbor site. The Participating Parties performed the tasks identified in the Second NOI (the Phase I Pipeline Investigation) and developed a proposal for additional investigation (the Phase 2 Pipeline Investigation), which proposal the EPA and DOH approved. The Participating Parties have completed the Phase 2 Pipeline Investigation and anticipate submitting a report to the DOH and EPA in the first quarter of 2003. With the approval of the EPA and DOH, the Participating Parties also constructed a pilot Dual Phase Extraction System to remove petroleum liquids and vapors from the subsurface in a portion of the Iwilei District. Operation of the pilot extraction system began in October 2002. The pilot study supplements ongoing petroleum removal activities by the Participating Parties from wells and trenches installed as part of the investigation. The Participating Parties are currently updating the Conceptual Site Model for the Iwilei Unit, In addition, the Participating Parties plan to

46

undertake a Feasibility Study during 2003 to identify and evaluate various remedial strategies to address petroleum products identified in the subsurface of the Iwilei District. Based on the Conceptual Site Model and the Feasibility Study, the Participating Parties will also recommend implementation of remedial strategies, where appropriate.

In October 2002, HECO and three other companies that currently have petroleum handling operations (the Operating Companies) in the Iwilei Unit entered into an agreement with the DOH to evaluate their facilities to determine whether they currently are releasing petroleum to the subsurface in the Iwilei Unit. HECO has previously investigated its facilities in the Iwilei Unit and routinely maintains them, and therefore believes that the Operating Companies evaluation will confirm that HECO’s current operations are not releasing petroleum in the Iwilei Unit.

Management has developed a preliminary estimate of costs for continuing investigative work, remedial activities and monitoring at the Iwilei Unit of the site. Management estimates that HECO will incur approximately $1.1 million (of which $0.2 million has been incurred through December 31, 2002) in connection with work to be performed at the site primarily from January 2002 through December 2004. This estimate was expensed in 2001. However, because (1) the full scope and extent of additional investigative work, remedial activities and monitoring are unknown at this time, (2) the final cost allocation method has not yet been determined and (3) management cannot estimate the costs to be incurred (if any) for the sites other than the Iwilei Unit (including its Honolulu power plant site), the cost estimate may be subject to significant change and additional material investigative and remedial costs may be incurred after December 2004.

Collective bargaining agreements

Approximately 62% of the employees of HECO, HELCO and MECO are represented by the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260 (IBEW), and are covered by collective bargaining agreements, which expire at midnight on October 31, 2003. Should the IBEW not reach agreements with HECO, HELCO and MECO in a timely manner upon the expiration of the existing agreements, HECO and its subsidiaries’ results of operations could be adversely affected.

12. Regulatory restrictions on distributions to parent

At December 31, 2002, net assets (assets less liabilities and preferred stock) of approximately $452 million were not available for transfer to HEI in the form of dividends, loans or advances without regulatory approval.

13. Related-party transactions

HEI charged HECO and its subsidiaries $2.2 million, $2.0 million and $1.8 million for general management and administrative services in 2002, 2001 and 2000, respectively. The amounts charged by HEI to its subsidiaries are allocated primarily on the basis of actual labor hours expended in providing such services.

HEI also charged HECO $2.1 million, $2.2 million and $2.5 million for data processing services in 2002, 2001 and 2000, respectively.

HECO’s borrowings from HEI fluctuate during the year, and totaled $5.6 million and $48.3 million at December 31, 2002 and 2001, respectively. The interest charged on short-term borrowings from HEI is based on the rate HEI pays on its commercial paper, provided HEI’s commercial paper rating is equal to or better than HECO’s rating. If HEI’s commercial paper rating falls below HECO’s, interest is based on HECO’s short-term external borrowing rate, or quoted rates from the Wall Street Journal for 30-day dealer-placed commercial paper. Interest charged by HEI to HECO totaled $0.4 million, $1.2 million and $0.1 million in 2002, 2001 and 2000, respectively.

14. Significant group concentrations of credit risk

HECO and its utility subsidiaries are regulated operating electric public utilities engaged in the generation, purchase, transmission, distribution and sale of electricity on the islands of Oahu, Hawaii, Maui, Lanai and Molokai in the State of Hawaii. HECO and its utility subsidiaries provide the only electric public utility service on the islands they serve. HECO and its utility subsidiaries grant credit to customers, all of whom reside or conduct business in the State of Hawaii.

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15. Fair value of financial instruments

The Company used the following methods and assumptions to estimate the fair value of each applicable class of financial instruments for which it is practicable to estimate that value:

Cash and equivalents and short-term borrowings

The carrying amount approximated fair value because of the short maturity of these instruments.

Long-term debt

Fair value was estimated based on quoted market prices for the same or similar issues of debt.

HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO and HECO-guaranteed debentures

Fair value was based on quoted market prices.

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

	December 31,
	2002				2001
	Carrying Amount		Estimated fair value		Carrying amount		Estimated fair value
	(in thousands)
Financial assets:
Cash and equivalents	$	1,726	$	1,726	$	1,858	$	1,858
Financial liabilities:
Short-term borrowings from affiliate		5,600		5,600		48,297		48,297
Long-term debt, net, including amounts due within one year		705,270		735,694		685,269		665,849
HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO and HECO-guaranteed debentures		100,000		100,120		100,000		100,400

Limitations

The Company makes fair value estimates at a specific point in time, based on relevant market information and information about the financial instrument. These estimates do not reflect any premium or discount that could result if the Company were to sell its entire holdings of a particular financial instrument at one time. Because no market exists for a significant portion of the Company’s financial instruments, fair value estimates cannot be determined with precision. Changes in assumptions could significantly affect the estimates.

Fair value estimates are provided for certain financial instruments without attempting to estimate the value of anticipated future business and the value of assets and liabilities that are not considered financial instruments. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates and have not been considered.

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16. Consolidating financial information (unaudited)

Consolidating balance sheet

	December 31, 2002
	HECO			HELCO			MECO			HECO Capital Trust I		HECO Capital Trust II		Reclassi- fications and Elimina-   tions			HECO Consolidated
	(in thousands)
Assets
Utility plant, at cost
Land	$	25,329		$	2,982		$	3,585		$	—	$	—	$	—		$	31,896
Plant and equipment		2,022,987			565,920			595,911			—		—		—			3,184,818
Less accumulated depreciation		(872,332	)		(255,473	)		(240,149	)		—		—		—			(1,367,954	)
Plant acquisition adjustment, net		—			—			302			—		—		—			302
Construction in progress		63,246			93,428			7,626			—		—		—			164,300
Net utility plant		1,239,230			406,857			367,275			—		—		—			2,013,362
Investment in wholly owned subsidiaries, at equity		355,869			—			—			—		—		(355,869	) [2]		—
Current assets
Cash and equivalents		9			4			1,713			—		—		—			1,726
Advances to affiliates		14,900			—			23,000			51,546		51,546		(140,992	) [1]		—
Customer accounts receivable, net		61,384			13,979			11,750			—		—		—			87,113
Accrued unbilled revenues, net		41,272			10,701			8,125			—		—		—			60,098
Other accounts receivable, net		2,582			411			462			—		—		(1,242	) [1]		2,213
Fuel oil stock, at average cost		25,701			3,446			6,502			—		—		—			35,649
Materials & supplies, at average cost		9,076			2,248			8,126			—		—		—			19,450
Prepayments and other		61,108			9,457			5,045			—		—		—			75,610
Total current assets		216,032			40,246			64,723			51,546		51,546		(142,234	)		281,859
Other assets
Regulatory assets		74,946			16,557			14,065			—		—		—			105,568
Unamortized debt expense		8,952			1,915			2,487			—		—		—			13,354
Long-term receivables and other		15,540			3,406			3,297			—		—		—			22,243
Total other assets		99,438			21,878			19,849			—		—		—			141,165
	$	1,910,569		$	468,981		$	451,847		$	51,546	$	51,546	$	(498,103	)	$	2,436,386
Capitalization and liabilities
Capitalization
Common stock equity	$	923,256		$	171,404		$	181,373		$	1,546	$	1,546	$	(355,869	) [2]	$	923,256
Cumulative preferred stock-not subject to mandatory redemption		22,293			7,000			5,000			—		—		—			34,293
HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO & HECO-guaranteed debentures		—			—			—			50,000		50,000		—			100,000
Long-term debt, net		495,689			140,993			171,680			—		—		(103,092	) [1]		705,270
Total capitalization		1,441,238			319,397			358,053			51,546		51,546		(458,961	)		1,762,819
Current liabilities
Short-term borrowings-affiliate		28,600			14,900			—			—		—		(37,900	) [1]		5,600
Accounts payable		41,594			10,462			7,936			—		—		—			59,992
Interest and preferred dividends payable		7,537			1,598			2,435			—		—		(38	) [1]		11,532
Taxes accrued		48,274			14,898			15,961			—		—		—			79,133
Other		20,998			3,679			4,547			—		—		(1,204	) [1]		28,020
Total current liabilities		147,003			45,537			30,879			—		—		(39,142	)		184,277
Deferred credits and other liabilities
Deferred income taxes		132,159			14,479			11,729			—		—		—			158,367
Unamortized tax credits		28,430			8,471			11,084			—		—		—			47,985
Other		23,441			26,809			14,594			—		—		—			64,844
Total deferred credits and other liabilities		184,030			49,759			37,407			—		—		—			271,196
Contributions in aid of construction		138,298			54,288			25,508			—		—		—			218,094
	$	1,910,569		$	468,981		$	451,847		$	51,546	$	51,546	$	(498,103	)	$	2,436,386

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Consolidating balance sheet

	December 31, 2001
	HECO			HELCO			MECO			HECO Capital Trust I		HECO Capital Trust II		Reclassi- fications and Elimina-   tions				HECO Consolidated
	(in thousands)
Assets
Utility plant, at cost
Land	$	25,369		$	2,752		$	3,568		$	—	$	—	$	—			$	31,689
Plant and equipment		1,943,378			550,671			574,205			—		—		—				3,068,254
Less accumulated depreciation		(810,187	)		(238,962	)		(217,183	)		—		—		—				(1,266,332	)
Plant acquisition adjustment, net		—			—			354			—		—		—				354
Construction in progress		70,501			85,913			14,144			—		—		—				170,558
Net utility plant		1,229,061			400,374			375,088			—		—		—				2,004,523
Investment in wholly owned subsidiaries, at equity		341,186			—			—			—		—		(341,186	)	[2]		—
Current assets
Cash and equivalents		9			1,282			567			—		—		—				1,858
Advances to affiliates		12,600			—			7,000			51,546		51,546		(122,692	)	[1]		—
Customer accounts receivable, net		56,227			13,644			12,001			—		—		—				81,872
Accrued unbilled revenues, net		35,072			8,855			8,696			—		—		—				52,623
Other accounts receivable, net		2,537			497			352			—		—		(734	)	[1]		2,652
Fuel oil stock, at average cost		15,840			3,007			5,593			—		—		—				24,440
Materials & supplies, at average cost		9,168			1,982			8,552			—		—		—				19,702
Prepayments and other		43,326			7,028			3,390			—		—		—				53,744
Total current assets		174,779			36,295			46,151			51,546		51,546		(123,426	)			236,891
Other assets
Regulatory assets		76,153			18,376			16,847			—		—		—				111,376
Unamortized debt expense		7,756			2,040			2,647			—		—		—				12,443
Long-term receivables and other		17,119			3,880			3,506			—		—		—				24,505
Total other assets		101,028			24,296			23,000			—		—		—				148,324
	$	1,846,054		$	460,965		$	444,239		$	51,546	$	51,546	$	(464,612	)		$	2,389,738
Capitalization and liabilities
Capitalization
Common stock equity	$	877,154		$	165,655		$	172,439		$	1,546	$	1,546	$	(341,186	)	[2]	$	877,154
Cumulative preferred stock–not subject to mandatory redemption		22,293			7,000			5,000			—		—		—				34,293
HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO & HECO-guaranteed debentures		—			—			—			50,000		50,000		—				100,000
Long-term debt, net		461,173			140,962			171,631			—		—		(103,092	)	[1]		670,674
Total capitalization		1,360,620			313,617			349,070			51,546		51,546		(444,278	)			1,682,121
Current liabilities
Long-term debt due within one year		9,595			5,000			—			—		—		—				14,595
Short-term borrowings-affiliate		55,297			12,600			—			—		—		(19,600	)	[1]		48,297
Accounts payable		34,860			10,108			8,998			—		—		—				53,966
Interest and preferred dividends payable		7,664			1,698			2,433			—		—		(30	)	[1]		11,765
Taxes accrued		52,216			15,841			18,001			—		—		—				86,058
Other		23,712			2,852			3,939			—		—		(704	)	[1]		29,799
Total current liabilities		183,344			48,099			33,371			—		—		(20,334	)			244,480
Deferred credits and other liabilities
Deferred income taxes		123,097			11,984			10,527			—		—		—				145,608
Unamortized tax credits		28,538			8,644			11,330			—		—		—				48,512
Other		15,557			25,309			14,594			—		—		—				55,460
Total deferred credits and other liabilities		167,192			45,937			36,451			—		—		—				249,580
Contributions in aid of construction		134,898			53,312			25,347			—		—		—				213,557
	$	1,846,054		$	460,965		$	444,239		$	51,546	$	51,546	$	(464,612	)		$	2,389,738

50

Consolidating statement of income

	Year ended December 31, 2002
	HECO			HELCO			MECO			HECO Capital Trust I		HECO Capital Trust II		Reclassi- fications and Elimina- tions				HECO Consolidated
	(in thousands)
Operating revenues	$	868,383		$	192,209		$	192,337		$	—	$	—	$	—			$	1,252,929
Operating expenses
Fuel oil		214,067			31,333			65,195			—		—		—				310,595
Purchased power		261,000			58,058			7,397			—		—		—				326,455
Other operation		83,190			21,697			27,023			—		—		—				131,910
Maintenance		41,411			13,437			11,693			—		—		—				66,541
Depreciation		63,613			19,548			22,263			—		—		—				105,424
Taxes, other than income taxes		83,089			18,424			18,605			—		—		—				120,118
Income taxes		37,380			7,899			11,450			—		—		—				56,729
		783,750			170,396			163,626			—		—		—				1,117,772
Operating income		84,633			21,813			28,711			—		—		—				135,157
Other income
Allowance for equity funds used during construction		3,514			217			223			—		—		—				3,954
Equity in earnings of subsidiaries		30,782			—			—			—		—		(30,782	)	[2]		—
Other, net		3,172			342			84			4,149		3,763		(8,369	)	[1]		3,141
		37,468			559			307			4,149		3,763		(39,151	)			7,095
Income before interest and other charges		122,101			22,372			29,018			4,149		3,763		(39,151	)			142,252
Interest and other charges
Interest on long-term debt		24,633			7,269			8,818			—		—		—				40,720
Amortization of net bond premium and expense		1,290			321			403			—		—		—				2,014
Other interest charges		6,535			1,922			1,410			—		—		(8,369	)	[1]		1,498
Allowance for borrowed funds used during construction		(1,642	)		(118	)		(95	)		—		—		—				(1,855	)
Preferred stock dividends of subsidiaries		—			—			—			—		—		915		[3]		915
Preferred securities distributions of trust subsidiaries		—			—			—			—		—		7,675		[3]		7,675
		30,816			9,394			10,536			—		—		221				50,967
Income before preferred stock dividends of HECO		91,285			12,978			18,482			4,149		3,763		(39,372	)			91,285
Preferred stock dividends of HECO		1,080			534			381			4,025		3,650		(8,590	)	[3]		1,080
Net income for common stock	$	90,205		$	12,444		$	18,101		$	124	$	113	$	(30,782	)		$	90,205

Consolidating statement of retained earnings

	Year ended December 31, 2002
(in thousands)	HECO			HELCO			MECO			HECO Capital Trust I			HECO Capital Trust II			Reclassi- fications and Elimina- tions			HECO Consolidated
Retained earnings, beginning of period	$	495,961		$	65,690		$	78,182		$	—		$	—		$	(143,872)	[2]	$	495,961
Net income for common stock		90,205			12,444			18,101			124			113			(30,782)	[2]		90,205
Common stock dividends		(44,143	)		(6,720	)		(9,191	)		(124	)		(113	)		16,148	[2]		(44,143	)
Retained earnings, end of period	$	542,023		$	71,414		$	87,092		$	—		$	—		$	(158,506)		$	542,023

51

Consolidating statement of income

	Year ended December 31, 2001
	HECO			HELCO			MECO			HECO Capital Trust I		HECO Capital Trust II		Reclassi- fications and Elimina-   tions					HECO Consolidated
	(in thousands)
Operating revenues	$	885,244		$	193,876		$	205,192		$	—	$	—	$	—				$	1,284,312
Operating expenses
Fuel oil		237,394			28,079			81,255			—		—		—					346,728
Purchased power		263,502			69,023			5,319			—		—		—					337,844
Other operation		80,825			19,181			25,559			—		—		—					125,565
Maintenance		39,258			9,444			13,099			—		—		—					61,801
Depreciation		60,799			18,522			21,393			—		—		—					100,714
Taxes, other than income taxes		83,310			18,315			19,269			—		—		—					120,894
Income taxes		35,774			8,362			11,298			—		—		—					55,434
		800,862			170,926			177,192			—		—		—					1,148,980
Operating income		84,382			22,950			28,000			—		—		—					135,332
Other income
Allowance for equity funds used during construction		3,506			286			447			—		—		—					4,239
Equity in earnings of subsidiaries		31,097			—			—			—		—		(31,097	)	[2	]		—
Other, net		3,447			486			210			4,149		3,763		(8,858	)	[1	]		3,197
		38,050			772			657			4,149		3,763		(39,955	)				7,436
Income before interest and other charges		122,432			23,722			28,657			4,149		3,763		(39,955	)				142,768
Interest and other charges
Interest on long-term debt		23,850			7,628			8,818			—		—		—					40,296
Amortization of net bond premium and expense		1,310			346			407			—		—		—					2,063
Other interest charges		9,775			2,411			1,369			—		—		(8,858	)	[1	]		4,697
Allowance for borrowed funds used during construction		(1,883	)		(174	)		(201	)		—		—		—					(2,258	)
Preferred stock dividends of subsidiaries		—			—			—			—		—		915		[3	]		915
Preferred securities distributions of trust subsidiaries		—			—			—			—		—		7,675		[3	]		7,675
		33,052			10,211			10,393			—		—		(268	)				53,388
Income before preferred stock dividends of HECO		89,380			13,511			18,264			4,149		3,763		(39,687	)				89,380
Preferred stock dividends of HECO		1,080			534			381			4,025		3,650		(8,590	)	[3	]		1,080
Net income for common stock	$	88,300		$	12,977		$	17,883		$	124	$	113	$	(31,097	)			$	88,300

Consolidating statement of retained earnings

	Year ended December 31, 2001
	HECO			HELCO			MECO			HECO Capital Trust I			HECO Capital Trust II			Reclassi- fications and Elimina-   tions					HECO Consolidated
	(in thousands)
Retained earnings, beginning of period	$	443,970		$	62,962		$	73,586		$	—		$	—		$	(136,548	)	[2	]	$	443,970
Net income for common stock		88,300			12,977			17,883			124			113			(31,097	)	[2	]		88,300
Common stock dividends		(36,309	)		(10,249	)		(13,287	)		(124	)		(113	)		23,773		[2	]		(36,309	)
Retained earnings, end of period	$	495,961		$	65,690		$	78,182		$	—		$	—		$	(143,872	)			$	495,961

52

Consolidating statement of income

	Year ended December 31, 2000
	HECO			HELCO			MECO			HECO Capital Trust I		HECO Capital Trust II		Reclassi- fications and Elimina- tions					HECO Consolidated
	(in thousands)
Operating revenues	$	883,414		$	192,918		$	194,303		$	—	$	—	$	—				$	1,270,635
Operating expenses
Fuel oil		236,298			49,439			77,168			—		—		—					362,905
Purchased power		262,764			41,668			6,775			—		—		—					311,207
Other operation		82,743			20,335			20,701			—		—		—					123,779
Maintenance		43,504			9,328			13,237			—		—		—					66,069
Depreciation		59,608			19,341			19,568			—		—		—					98,517
Taxes, other than income taxes		83,169			18,222			18,393			—		—		—					119,784
Income taxes		34,256			9,480			11,477			—		—		—					55,213
		802,342			167,813			167,319			—		—		—					1,137,474
Operating income		81,072			25,105			26,984			—		—		—					133,161
Other income
Allowance for equity funds used during construction		4,245			232			903			—		—		—					5,380
Equity in earnings of subsidiaries		32,985			—			—			—		—		(32,985	)	[2	]		—
Other, net		4,810			736			958			4,149		3,763		(9,861	)	[1	]		4,555
		42,040			968			1,861			4,149		3,763		(42,846	)				9,935
Income before interest and other charges		123,112			26,073			28,845			4,149		3,763		(42,846	)				143,096
Interest and other charges
Interest on long-term debt		23,369			7,621			9,144			—		—		—					40,134
Amortization of net bond premium and expense		1,262			315			361			—		—		—					1,938
Other interest charges		12,459			3,007			1,385			—		—		(9,861	)	[1	]		6,990
Allowance for borrowed funds used during construction		(2,344	)		(139	)		(439	)		—		—		—					(2,922	)
Preferred stock dividends of subsidiaries		—			—			—			—		—		915		[3	]		915
Preferred securities distributions of trust subsidiaries		—			—			—			—		—		7,675		[3	]		7,675
		34,746			10,804			10,451			—		—		(1,271	)				54,730
Income before preferred stock dividends of HECO		88,366			15,269			18,394			4,149		3,763		(41,575	)				88,366
Preferred stock dividends of HECO		1,080			534			381			4,025		3,650		(8,590	)	[3	]		1,080
Net income for common stock	$	87,286		$	14,735		$	18,013		$	124	$	113	$	(32,985	)			$	87,286

Consolidating statement of retained earnings

	Year ended December 31, 2000
	HECO			HELCO			MECO			HECO Capital Trust I			HECO Capital Trust II			Reclassi- fications and Elimina- tions					HECO Consolidated
	(in thousands)
Retained earnings, beginning of period	$	425,206		$	59,806		$	69,633		$	—		$	—		$	(129,439	)	[2	]	$	425,206
Net income for common stock		87,286			14,735			18,013			124			113			(32,985	)	[2	]		87,286
Common stock dividends		(68,522	)		(11,579	)		(14,060	)		(124	)		(113	)		25,876		[2	]		(68,522	)
Retained earnings, end of period	$	443,970		$	62,962		$	73,586		$	—		$	—		$	(136,548	)			$	443,970

53

Consolidating statement of cash flows

	Year ended December 31, 2002
	HECO			HELCO			MECO			HECO Capital Trust I			HECO Capital Trust II			Reclassi- fications and Elimina- tions				HECO Consolidated
(in thousands)
Cash flows from operating activities:
Income before preferred stock dividends of HECO	$	91,285		$	12,978		$	18,482		$	4,149		$	3,763		$	(39,372	)	[2]	$	91,285
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Equity in earnings		(30,782	)		—			—						—			30,782		[2]		—
Common stock dividends received from subsidiaries		16,148			—			—			—			—			(16,148	)	[2]		—
Depreciation of property, plant and equipment		63,613			19,548			22,263			—			—			—				105,424
Other amortization		3,949			1,873			5,554			—			—			—				11,376
Deferred income taxes		9,118			2,495			1,205			—			—			—				12,818
Tax credits, net		953			61			17			—			—			—				1,031
Allowance for equity funds used during construction		(3,514	)		(217	)		(223	)		—			—			—				(3,954	)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable		(5,202	)		(249	)		141			—			—			508		[1]		(4,802	)
Decrease (increase) in accrued unbilled revenues		(6,200	)		(1,846	)		571			—			—			—				(7,475	)
Increase in fuel oil stock		(9,861	)		(439	)		(909	)		—			—			—				(11,209	)
Decrease (increase) in materials and supplies		92			(266	)		426			—			—			—				252
Decrease (increase) in regulatory assets		112			418			(2,411	)		—			—			—				(1,881	)
Increase (decrease) in accounts payable		6,734			354			(1,062	)		—			—			—				6,026
Decrease in taxes accrued		(3,942	)		(943	)		(2,040	)		—			—			—				(6,925	)
Changes in other assets and liabilities		(25,264	)		(1,220	)		(1,072	)		—			—			7,167		[2]		(20,389	)
Net cash provided by operating activities		107,239			32,547			40,942			4,149			3,763			(17,063	)			171,577
Cash flows from investing activities:
Capital expenditures		(71,316	)		(27,541	)		(15,701	)		—			—			—				(114,558	)
Contributions in aid of construction		6,042			3,518			1,482			—			—			—				11,042
Advances to affiliates		(2,300	)		—			(16,000	)		—			—			18,300		[1]		—
Other		56			—			—			—			—			—				56
Net cash used in investing activities		(67,518	)		(24,023	)		(30,219	)		—			—			18,300				(103,460	)
Cash flows from financing activities:
Common stock dividends		(44,143	)		(6,720	)		(9,191	)		(124	)		(113	)		16,148		[2]		(44,143	)
Preferred stock dividends		(1,080	)		(534	)		(381	)		—			—			915		[2]		(1,080	)
Preferred securities distributions of trust subsidiaries		—			—			—			(4,025	)		(3,650	)		—				(7,675	)
Proceeds from issuance of long-term debt		35,275			—			—			—			—			—				35,275
Repayment of long-term debt		—			(5,000	)		—			—			—			—				(5,000	)
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		(26,697	)		2,300			—			—			—			(18,300	)	[1]		(42,697	)
Other		(3,076	)		152			(5	)		—			—			—				(2,929	)
Net cash used in financing activities		(39,721	)		(9,802	)		(9,577	)		(4,149	)		(3,763	)		(1,237	)			(68,249	)
Net increase (decrease) in cash and equivalents		—			(1,278	)		1,146			—			—			—				(132	)
Cash and equivalents, beginning of period		9			1,282			567			—			—			—				1,858
Cash and equivalents, end of period	$	9		$	4		$	1,713		$	—		$	—		$	—			$	1,726

54

Consolidating statement of cash flows

	Year ended December 31, 2001
	HECO			HELCO			MECO			HECO Capital Trust I			HECO Capital Trust II			Reclassi- fications and Elimina-   tions				HECO Consolidated
	(in thousands)
Cash flows from operating activities:
Income before preferred stock dividends of HECO	$	89,380		$	13,511		$	18,264		$	4,149		$	3,763		$	(39,687	)	[2]	$	89,380
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Equity in earnings		(31,097	)		—			—			—			—			31,097		[2]		—
Common stock dividends received from subsidiaries		23,773			—			—			—			—			(23,773	)	[2]		—
Depreciation of property, plant and equipment		60,799			18,522			21,393			—			—			—				100,714
Other amortization		5,157			2,054			5,529			—			—			—				12,740
Deferred income taxes		6,471			1,448			638			—			—			—				8,557
Tax credits, net		1,429			(95	)		1,142			—			—			—				2,476
Allowance for equity funds used during construction		(3,506	)		(286	)		(447	)		—			—			—				(4,239	)
Changes in assets and liabilities:
Decrease in accounts receivable		6,031			1,801			918			—			—			698		[1]		9,448
Decrease in accrued unbilled revenues		9,376			1,289			732			—			—			—				11,397
Decrease in fuel oil stock		8,336			432			3,916			—			—			—				12,684
Decrease (increase) in materials and supplies		(2,210	)		383			(1,088	)		—			—			—				(2,915	)
Increase in regulatory assets		(1,212	)		(255	)		(2,569	)		—			—			—				(4,036	)
Decrease in accounts payable		(16,389	)		(38	)		(1,305	)		—			—			—				(17,732	)
Increase in taxes accrued		6,122			269			1,481			—			—			—				7,872
Changes in other assets and liabilities		(29,548	)		(2,373	)		(2,653	)		—			—			6,977		[2]		(27,597	)
Net cash provided by operating activities		132,912			36,662			45,951			4,149			3,763			(24,688	)			198,749
Cash flows from investing activities:
Capital expenditures		(69,353	)		(20,503	)		(25,684	)		—			—			—				(115,540	)
Contributions in aid of construction		4,343			4,279			2,336			—			—			—				10,958
Advances to affiliates		9,200			—			(7,000	)		—			—			(2,200	)	[1]		—
Net cash used in investing activities		(55,810	)		(16,224	)		(30,348	)		—			—			(2,200	)			(104,582	)
Cash flows from financing activities:
Common stock dividends		(36,309	)		(10,249	)		(13,287	)		(124	)		(113	)		23,773		[2]		(36,309	)
Preferred stock dividends		(1,080	)		(534	)		(381	)		—			—			915		[2]		(1,080	)
Preferred securities distributions of trust subsidiaries		—			—			—			(4,025	)		(3,650	)		—				(7,675	)
Proceeds from issuance of long-term debt		17,336			—			—			—			—			—				17,336
Net decrease in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		(54,869	)		(7,700	)		(1,500	)		—			—			2,200		[1]		(61,869	)
Repayment of other short-term borrowings		(3,000	)		—			—			—			—			—				(3,000	)
Other		(569	)		(677	)		—			—			—			—				(1,246	)
Net cash used in financing activities		(78,491	)		(19,160	)		(15,168	)		(4,149	)		(3,763	)		26,888				(93,843	)
Net increase (decrease) in cash and equivalents		(1,389	)		1,278			435			—			—			—				324
Cash and equivalents, beginning of period		1,398			4			132			—			—			—				1,534
Cash and equivalents, end of period	$	9		$	1,282		$	567		$	—		$	—		$	—			$	1,858

55

Consolidating statement of cash flows

	Year ended December 31, 2000
	HECO			HELCO			MECO			HECO Capital Trust I			HECO Capital Trust II			Reclassi- fications and Elimina- tions			HECO Consolidated
(in thousands)
Cash flows from operating activities:
Income before preferred stock dividends of HECO	$	88,366		$	15,269		$	18,394		$	4,149		$	3,763		$	(41,575	)[2]	$	88,366
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Equity in earnings		(32,985	)		—			—			—			—			32,985	[2]		—
Common stock dividends received from subsidiaries		25,876			—			—			—			—			(25,876	)[2]		—
Depreciation of property, plant and equipment		59,608			19,341			19,568			—			—			—			98,517
Other amortization		4,835			1,335			2,638			—			—			—			8,808
Deferred income taxes		5,297			122			542			—			—			—			5,961
Tax credits, net		997			(28	)		13												982
Allowance for equity funds used during construction		(4,245	)		(232	)		(903	)		—			—			—			(5,380	)
Changes in assets and liabilities:
Increase in accounts receivable		(17,865	)		(2,867	)		(3,128	)		—			—			828	[1]		(23,032	)
Increase in accrued unbilled revenues		(6,994	)		(1,220	)		(1,976	)		—			—			—			(10,190	)
Decrease (increase) in fuel oil stock		262			171			(2,603	)		—			—			—			(2,170	)
Decrease in materials and supplies		2,138			830			291			—			—			—			3,259
Increase in regulatory assets		(2,595	)		(696	)		(2,457	)		—			—			—			(5,748	)
Increase in accounts payable		14,591			3,169			1,822			—			—			—			19,582
Increase in taxes accrued		8,218			2,367			1,066			—			—			—			11,651
Changes in other assets and liabilities		(25,528	)		79			(2,558	)		—			—			6,847	[2]		(21,160	)
Net cash provided by operating activities		119,976			37,640			30,709			4,149			3,763			(26,791	)		169,446
Cash flows from investing activities:
Capital expenditures		(78,786	)		(22,791	)		(28,512	)		—			—			—			(130,089	)
Contributions in aid of construction		3,773			3,289			1,422			—			—			—			8,484
Advances to affiliates		4,400			—			8,400			—			—			(12,800	)[1]		—
Payments on notes receivable		—			138			—			—			—			—			138
Net cash used in investing activities		(70,613	)		(19,364	)		(18,690	)		—			—			(12,800	)		(121,467	)
Cash flows from financing activities:
Common stock dividends		(68,522	)		(11,579	)		(14,060	)		(124	)		(113	)		25,876	[2]		(68,522	)
Preferred stock dividends		(1,080	)		(534	)		(381	)		—			—			915	[2]		(1,080	)
Preferred securities distributions of trust subsidiaries		—			—			—			(4,025	)		(3,650	)		—			(7,675	)
Proceeds from issuance of long-term debt		67,081			91			20,335			—			—			—			87,507
Repayment of long-term debt		(46,000	)		—			(20,000	)		—			—			—			(66,000	)
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		(5,247	)		(5,900	)		1,500			—			—			12,800	[1]		3,153
Proceeds from other short-term borrowings		57,499			—			—			—			—			—			57,499
Repayment of other short-term borrowings		(55,682	)		—			—			—			—			—			(55,682	)
Other		2,947			(548	)		(10	)		—			—			—			2,389
Net cash used in financing activities		(49,004	)		(18,470	)		(12,616	)		(4,149	)		(3,763	)		39,591			(48,411	)
Net increase (decrease) in cash and equivalents		359			(194	)		(597	)		—			—			—			(432	)
Cash and equivalents, beginning of period		1,039			198			729			—			—			—			1,966
Cash and equivalents, end of period	$	1,398		$	4		$	132		$	—		$	—		$	—		$	1,534

56

Explanation of reclassifications and eliminations on consolidating schedules

[1] Eliminations of intercompany receivables and payables and other intercompany transactions.

[2] Elimination of investment in subsidiaries, carried at equity.

[3] Reclassification of preferred stock dividends of Hawaii Electric Light Company, Inc. and Maui Electric Company, Limited and of preferred securities distributions of HECO Capital Trust I and HECO Capital Trust II for financial statement presentation.

HECO has not provided separate financial statements and other disclosures concerning HELCO and MECO because management has concluded that such financial statements and other information are not material to holders of the 1997 and 1998 junior deferrable debentures issued by HELCO and MECO to HECO Capital Trust I and HECO Capital Trust II, which debentures have been fully and unconditionally guaranteed by HECO.

17. Consolidated quarterly financial information (unaudited)

Selected quarterly consolidated financial information of the Company for 2002 and 2001 follows:

	Quarters ended
	2002
	March 31		June 30		Sept. 30		Dec. 31		Year ended Dec. 31
	(in thousands)
Operating revenues	$	277,333	$	306,616	$	332,453	$	336,527	$	1,252,929
Operating income		31,921		35,082		36,512		31,642		135,157
Net income for common stock		20,359		23,850		25,610		20,386		90,205
	Quarters ended
	2001
	March 31		June 30		Sept. 30		Dec. 31		Year ended Dec. 31
	(in thousands)
Operating revenues	$	317,293	$	312,455	$	340,231	$	314,333	$	1,284,312
Operating income		33,457		34,627		37,526		29,722		135,332
Net income for common stock		21,425		22,716		25,695		18,464		88,300

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

57

Directors and Executive Officers

HAWAIIAN ELECTRIC COMPANY, INC.
DIRECTORS
Robert F. Clarke, 60, 1990	James K. Scott, 51, 1999
T. Michael May, 56, 1995	Anne M. Takabuki, 46, 1997 [1]
Shirley J. Daniel, 49, 2002 [1]	Barry K. Taniguchi, 55, 2001 [1]
Diane J. Plotts, 67, 1991 [1]	Jeffrey N. Watanabe, 60, 1999
[1] Audit committee member.
Note: Year indicates first year elected or appointed. All directors serve one year terms.
OFFICERS
Robert F. Clarke	Chris M. Shirai
Chairman of the Board	Vice President-Energy Delivery
T. Michael May	Thomas C. Simmons
President and Chief Executive Officer	Vice President-Power Supply
Robert A. Alm	Richard A. von Gnechten
Senior Vice President-Public Affairs	Financial Vice President
Thomas L. Joaquin	Patricia U. Wong
Senior Vice President-Operations	Vice President-Corporate Excellence
Karl E. Stahlkopf	Lorie Ann K. Nagata
Senior Vice President-Energy Solutions and Chief Technology Officer	Treasurer
William A. Bonnet	Ernest T. Shiraki
Vice President-Government & Community Affairs	Controller
Jackie Mahi Erickson	Molly M. Egged
Vice President-Customer Operations & General Counsel	Secretary
Charles M. Freedman
Vice President-Corporate Relations
HAWAII ELECTRIC LIGHT COMPANY, INC.
DIRECTORS	ADVISORY BOARD MEMBERS
T. Michael May	T. Michael May, Chairman
Robert F. Clarke	Carol R. Ignacio
Warren H. W. Lee	Warren H. W. Lee
	Barry K. Taniguchi
	Thomas P. Whittemore
	Donald K. Yamada
OFFICERS
T. Michael May	Lorie Ann K. Nagata
Chairman of the Board	Treasurer
Warren H. W. Lee	Molly M. Egged
President	Secretary
Richard A. von Gnechten
Financial Vice President
William A. Bonnet
Vice President
MAUI ELECTRIC COMPANY, LIMITED
DIRECTORS	ADVISORY BOARD MEMBERS
T. Michael May	T. Michael May, Chairman
Robert F. Clarke	Gladys C. Baisa
Edward L. Reinhardt	B. Martin Luna
	Boyd P. Mossman
	Edward L. Reinhardt
	Anne M. Takabuki
OFFICERS
T. Michael May	Lorie Ann K. Nagata
Chairman of the Board	Treasurer
Edward L. Reinhardt	Molly M. Egged
President	Secretary
Richard A. von Gnechten
Financial Vice President
William A. Bonnet
Vice President

Information provided as of February 12, 2003

59

EX-99.1

HEI Exhibit 99.1

Hawaiian Electric Industries, Inc.

Written Statement of Chief Executive Officer Pursuant to

18 U.S.C. Section 1350,

as Adopted by

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the 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, 2002 and results of operations for the year ended December 31, 2002 of HEI and its subsidiaries.

/s/ Robert F. Clarke

Robert F. Clarke

Chairman, President and Chief Executive Officer of HEI

Date: February 26, 2003

EX-99.2

HEI Exhibit 99.2

Hawaiian Electric Industries, Inc.

Written Statement of Chief Financial Officer Pursuant to

18 U.S.C. Section 1350,

as Adopted by

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the 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, 2002 and results of operations for the year ended December 31, 2002 of HEI and its subsidiaries.

/s/ Eric K. Yeaman

Eric K. Yeaman

Financial Vice President, Treasurer and Chief Financial Officer of HEI

Date: February 26, 2003

EX-99.3

HECO Exhibit 99.3

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, 2002 and results of operations for the year ended December 31, 2002 of HECO and its subsidiaries.

/s/ T. Michael May

T. Michael May

President and Chief Executive Officer of HECO

Date: February 26, 2003

EX-99.4

HECO Exhibit 99.4

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, 2002 and results of operations for the year ended December 31, 2002 of HECO and its subsidiaries.

/s/ Richard A. von Gnechten

Richard A. von Gnechten

Financial Vice President

(Principal Financial Officer of HECO)

Date: February 26, 2003