HECO Exhibit 99

Consolidated Statements of Income

Hawaiian Electric Company, Inc. and Subsidiaries

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

Consolidated Statements of Retained Earnings

Hawaiian Electric Company, Inc. and Subsidiaries

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

See accompanying “Notes to Consolidated Financial Statements.”

Consolidated Balance Sheets

Hawaiian Electric Company, Inc. and Subsidiaries

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

See accompanying “Notes to Consolidated Financial Statements.”

2

Consolidated Statements of Capitalization

Hawaiian Electric Company, Inc. and Subsidiaries

December 31	2003		2002		2001
(dollars in thousands, except per share amounts)
Common stock equity
Common stock of $6 2/3 par value
Authorized: 50,000,000 shares. Outstanding: 2003, 2002 and 2001, 12,805,843 shares	$	85,387	$	85,387	$	85,387
Premium on capital stock		295,841		295,846		295,806
Retained earnings		563,215		542,023		495,961
Common stock equity		944,443		923,256		877,154
Cumulative preferred stock not subject to mandatory redemption
Authorized: 5,000,000 shares of $20 par value and 7,000,000 shares of $100 par value. Outstanding: 2003 and 2002, 1,234,657 shares.

Series	Par Value				Shares Outstanding December 31, 2003	2003		2002
(dollars in thousands, except par value and shares outstanding)
C-4 1/4%	$	20	(HECO	)	150,000		3,000		3,000
D-5%		20	(HECO	)	50,000		1,000		1,000
E-5%		20	(HECO	)	150,000		3,000		3,000
H-5 1/4%		20	(HECO	)	250,000		5,000		5,000
I-5%		20	(HECO	)	89,657		1,793		1,793
J-4 3/4%		20	(HECO	)	250,000		5,000		5,000
K-4.65%		20	(HECO	)	175,000		3,500		3,500
G-7 5/8%		100	(HELCO	)	70,000		7,000		7,000
H-7 5/8%		100	(MECO	)	50,000		5,000		5,000
					1,234,657	$	34,293	$	34,293

(continued)

See accompanying “Notes to Consolidated Financial Statements.”

3

Consolidated Statements of Capitalization, continued

Hawaiian Electric Company, Inc. and Subsidiaries

December 31	2003		2002
(in thousands)
HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO and HECO-guaranteed debentures (distribution rates of 7.30% and 8.05%)	$	100,000	$	100,000
Long-term debt
Obligations to the State of Hawaii for the repayment of Special Purpose Revenue Bonds:
HECO, 5.00%, refunding series 2003B, due 2022		40,000		—
HELCO, 5.00%, refunding series 2003B, due 2022		12,000		—
HELCO, 4.75%, refunding series 2003A, due 2020		14,000		—
HECO, 5.10%, series 2002A, due 2032		40,000		40,000
HECO, 5.70%, refunding series 2000, due 2020		46,000		46,000
MECO, 5.70%, refunding series 2000, due 2020		20,000		20,000
HECO, 6.15%, refunding series 1999D, due 2020		16,000		16,000
HELCO, 6.15%, refunding series 1999D, due 2020		3,000		3,000
MECO, 6.15%, refunding series 1999D, due 2020		1,000		1,000
HECO, 6.20%, series 1999C, due 2029		35,000		35,000
HECO, 5.75%, refunding series 1999B, due 2018		30,000		30,000
HELCO, 5.75% refunding series 1999B, due 2018		11,000		11,000
MECO, 5.75%, refunding series 1999B, due 2018		9,000		9,000
HELCO, 5.50%, refunding series 1999A, due 2014		11,400		11,400
HECO, 4.95%, refunding series 1998A, due 2012		42,580		42,580
HELCO, 4.95%, refunding series 1998A, due 2012		7,200		7,200
MECO, 4.95%, refunding series 1998A, due 2012		7,720		7,720
HECO, 5.65%, series 1997A, due 2027		50,000		50,000
HELCO, 5.65%, series 1997A, due 2027		30,000		30,000
MECO, 5.65%, series 1997A, due 2027		20,000		20,000
HECO, 5 7/8%, series 1996B, due 2026		14,000		14,000
HELCO, 5 7/8%, series 1996B, due 2026		1,000		1,000
MECO, 5 7/8%, series 1996B, due 2026		35,000		35,000
HECO, 6.20%, series 1996A, due 2026		48,000		48,000
HELCO, 6.20%, series 1996A, due 2026		7,000		7,000
MECO, 6.20%, series 1996A, due 2026		20,000		20,000
HECO, 6.60%, series 1995A, due 2025		40,000		40,000
HELCO, 6.60%, series 1995A, due 2025		5,000		5,000
MECO, 6.60%, series 1995A, due 2025		2,000		2,000
HECO, 5.45%, series 1993, due 2023		50,000		50,000
HELCO, 5.45%, series 1993, due 2023		20,000		20,000
MECO, 5.45%, series 1993, due 2023		30,000		30,000
HECO, 6.55%, series 1992, due 2022		—		40,000
HELCO, 6.55%, series 1992, due 2022		—		12,000
MECO, 6.55%, series 1992, due 2022		—		8,000
HELCO, 7 3/8%, series 1990C, due 2020		—		10,000
HELCO, 7.60%, series 1990B, due 2020		—		4,000
		717,900		725,900
Less funds on deposit with trustees		14,013		16,111
Total obligations to the State of Hawaii		703,887		709,789
Less unamortized discount		4,467		4,519
Long-term debt, net		699,420		705,270
Total capitalization	$	1,778,156	$	1,762,819

See accompanying “Notes to Consolidated Financial Statements.”

4

Consolidated Statements of Cash Flows

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31	2003			2002			2001
(in thousands)
Cash flows from operating activities
Income before preferred stock dividends of HECO	$	79,991		$	91,285		$	89,380
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Depreciation of utility plant		110,560			105,424			100,714
Other amortization		8,232			11,376			12,740
Deferred income taxes		12,519			12,818			8,557
Tax credits, net		585			1,031			2,476
Allowance for equity funds used during construction		(4,267	)		(3,954	)		(4,239	)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable		(5,006	)		(4,802	)		9,448
Decrease (increase) in accrued unbilled revenues		(274	)		(7,475	)		11,397
Decrease (increase) in fuel oil stock		(7,963	)		(11,209	)		12,684
Decrease (increase) in materials and supplies		(1,783	)		252			(2,915	)
Increase in regulatory assets, net		(4,897	)		(1,881	)		(4,036	)
Increase (decrease) in accounts payable		12,385			6,026			(17,732	)
Increase (decrease) in taxes accrued		14,170			(6,925	)		7,872
Other		(8,196	)		(20,389	)		(27,597	)
Net cash provided by operating activities		206,056			171,577			198,749
Cash flows from investing activities
Capital expenditures		(146,964	)		(114,558	)		(115,540	)
Contributions in aid of construction		12,963			11,042			10,958
Proceeds from sales of assets		118			56			—
Net cash used in investing activities		(133,883	)		(103,460	)		(104,582	)
Cash flows from financing activities
Common stock dividends		(57,719	)		(44,143	)		(36,309	)
Preferred stock dividends		(1,080	)		(1,080	)		(1,080	)
Preferred securities distributions of trust subsidiaries		(7,675	)		(7,675	)		(7,675	)
Proceeds from issuance of long-term debt		67,935			35,275			17,336
Repayment of long-term debt		(74,000	)		(5,000	)		—
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		400			(42,697	)		(61,869	)
Repayment of other short-term borrowings		—			—			(3,000	)
Other		(1,602	)		(2,929	)		(1,246	)
Net cash used in financing activities		(73,741	)		(68,249	)		(93,843	)
Net increase (decrease) in cash and equivalents		(1,568	)		(132	)		324
Cash and equivalents, January 1		1,726			1,858			1,534
Cash and equivalents, December 31	$	158		$	1,726		$	1,858

See accompanying “Notes to Consolidated Financial Statements.”

5

Notes to Consolidated Financial Statements

Hawaiian Electric Company, Inc. and Subsidiaries

1. Summary of significant accounting policies

General

Hawaiian Electric Company, Inc. (HECO) and its wholly-owned operating subsidiaries, Hawaii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (MECO), are electric public utilities in the business of generating, purchasing, transmitting, distributing and selling electric energy on all major islands in Hawaii other than Kauai, and are regulated by the Public Utilities Commission of the State of Hawaii (PUC). HECO also owns non-regulated subsidiaries: Renewable Hawaii, Inc. (RHI), which will invest in renewable energy projects; HECO Capital Trust I and HECO Capital Trust II, which are financing entities; and HECO Capital Trust III, which was formed in November 2003 in connection with a possible future financing.

Basis of presentation

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

Material estimates that are particularly susceptible to significant change include the amounts reported for property, plant and equipment; pension and other postretirement benefit obligations; contingencies and litigation; income taxes; regulatory assets and liabilities; and revenues.

Consolidation

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

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

HECO, HELCO and MECO are regulated by the PUC and account for the effects of regulation under Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.” As a result, the actions of regulators can affect the timing of recognition of revenues, expenses, assets and liabilities. Management believes HECO and its subsidiaries’ operations currently satisfy the SFAS No. 71 criteria. If events or circumstances should change so that those criteria are no longer satisfied, the Company expects that the regulatory liabilities, net of regulatory assets, would be credited to income. In the event of unforeseen regulatory actions or other circumstances, however, management believes that a material adverse effect on the Company’s results of operations and financial position may result if regulatory assets have to be charged to expense without an offsetting credit from regulatory liabilities.

Utility plant

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

6

Depreciation

Depreciation is computed primarily using the straight-line method over the estimated useful lives of the assets being depreciated. Utility plant has useful lives ranging from 20 to 45 years for production plant, from 25 to 50 years for transmission and distribution plant and from 8 to 45 years for general plant. The composite annual depreciation rate was 3.9% in 2003, 2002 and 2001.

Cash and equivalents

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

Accounts receivable

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

Retirement benefits

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

Financing costs

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

Contributions in aid of construction

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

7

Electric utility revenues

Electric utility revenues are based on rates authorized by the PUC and include revenues applicable to energy consumed in the accounting period but not yet billed to the customers. Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers for billing purposes is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on the meter readings in the beginning of the following month, monthly generation volumes, estimated customer usage by account, line losses and applicable customer rates based on historical values and current rate schedules. At December 31, 2003, customer accounts receivable include unbilled energy revenues of $60 million on a base of annual revenue of $1.4 billion. Revenue amounts recorded pursuant to a PUC interim order are subject to refund, with interest, pending a final order.

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

The Company’s operating revenues include amounts for various revenue taxes the electric utilities collect from customers and pay to taxing authorities. Revenue taxes to be paid to the taxing authorities are recorded as an expense and a corresponding liability in the year the related revenues are recognized. Payments to the taxing authorities are made in the subsequent year. For 2003 and 2001, the Company included $123 million and $114 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense. For 2002, the Company included $111 million of revenue taxes in “operating revenues” and $113 million (including a $2 million nonrecurring PUC fee adjustment) of revenue taxes in “taxes, other than income taxes” expense.

Allowance for Funds Used During Construction (AFUDC)

AFUDC is an accounting practice whereby the costs of debt (AFUDC-Debt) and equity (AFUDC-Equity) funds used to finance plant construction are credited on the statement of income and charged to construction in progress on the balance sheet. If a project under construction is delayed for an extended period of time, AFUDC may be stopped.

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

Environmental expenditures

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

Income taxes

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

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

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

8

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

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

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

Recent accounting pronouncements and interpretations

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

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

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

9

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

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

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

10

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

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

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

Reclassifications

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

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2. Cumulative preferred stock

The following series of cumulative preferred stock are redeemable only at the option of the respective company and are subject to payment of the following prices in the event of voluntary liquidation or redemption:

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

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

3. HECO-obligated mandatorily redeemable trust preferred securities of

     subsidiary trusts holding solely HECO and HECO-guaranteed debentures

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

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

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

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

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

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

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

4. Long-term debt

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

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

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

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

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

5. Short-term borrowings

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

At December 31, 2003 and 2002, the Company maintained bank lines of credit which totaled $90 million ($50 million maturing in April 2004, $10 million maturing in May 2004 and $30 million maturing in June 2004) and $100 million, respectively. HECO maintains these lines of credit (at a base rate [Prime, Fed Funds, Bank Base, Bank Quoted, Eurodollar or LIBOR rate] plus a margin ranging from 0 to 80 basis points) to support the issuance of commercial paper and for other general corporate purposes. None of the lines are secured. There were no borrowings under any line of credit during 2003 and 2002.

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6. Regulatory assets and liabilities

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

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

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

Integrated Resource Planning costs

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

The PUC has allowed the Company to recover IRP costs pending the PUC’s final decision and order approving recovery of each respective year’s IRP costs. Recovery of IRP costs is subject to refund with interest. HECO has been allowed and has fully recovered its deferred IRP costs for years 1995 through 2002. MECO has been allowed to recover its deferred IRP costs for years 1995 through 2002, and is currently recovering costs incurred for year 2002. HELCO has been allowed and has fully recovered its deferred IRP costs for years 1995 through 2000. HELCO’s costs for year 2001 and subsequent years are included in its base rates. As of December 31, 2003, the aggregate amount of revenues recorded by all three companies to recover deferred IRP costs, which are subject to refund with interest, amounted to $16.6 million.

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7. Income taxes

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

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

Income tax benefits related to nonoperating activities, included in “Other, net” on the consolidated statements of income, amounted to $351,000, $71,000 and $18,000 for 2003, 2002 and 2001, respectively.

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

December 31	2003			2002			2001
(in thousands)
Amount at the federal statutory income tax rate	$	46,235		$	52,226		$	51,005
State income taxes on operating income, net of effect on federal income taxes		4,121			4,854			4,743
Other		(181	)		(351	)		(314	)
Income taxes charged to operating expenses	$	50,175		$	56,729		$	55,434

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

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

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The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Based upon historical taxable income, projections for future taxable income and tax planning strategies, management believes it is more likely than not the Company will realize the benefits of the deferred tax assets and has provided no valuation allowance for deferred tax assets during 2003, 2002 and 2001.

8. Cash flows

Supplemental disclosures of cash flow information

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

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

Supplemental disclosures of noncash activities

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

The estimated fair value of noncash contributions in aid of construction amounted to $13.9 million, $4.4 million and $2.4 million in 2003, 2002 and 2001, respectively.

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

9. Major customers

HECO and its subsidiaries received approximately 10% ($135 million), 9% ($119 million) and 10% ($127 million) of their operating revenues from the sale of electricity to various federal government agencies in 2003, 2002 and 2001, respectively.

10. Retirement benefits

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

The Plan and the Supplemental/Excess/Directors Plans were adopted with the expectation that they will continue indefinitely, but the continuation of these plans and the payment of any contribution thereunder is not assumed as a contractual obligation by the participating employers. The Directors’ Plan has been frozen since 1996, and no participants have accrued any benefits after that time. The plan will be terminated at the time all remaining benefits have been paid.

Each participating employer reserves the right to terminate its participation in the applicable plans at any time. If a participating employer terminated its participation in the Plans, the interest of each affected participant would become 100% vested to the extent funded. Upon the termination of the Plans, assets would be distributed to affected participants in accordance with the applicable allocation provisions of ERISA and any excess assets that

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

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

To determine pension costs for HECO, HELCO and MECO under the Plan and the Supplemental/Excess/Directors Plans, it is necessary to make complex calculations and estimates based on numerous assumptions, including the assumptions identified below.

Postretirement benefits other than pensions. The Company provides eligible employees health and life insurance benefits upon retirement under the Postretirement Welfare Benefits Plan for Employees of Hawaiian Electric Company, Inc. and Participating Employers. Health benefits are also provided to dependents of eligible employees. The contribution for health benefits paid by the participating employers is based on retirees’ years of service and retirement dates. Generally, employees are eligible for these benefits if, upon retirement from active employment, they are eligible to receive benefits from the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries.

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

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

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

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

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

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

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

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

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

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

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

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

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

	Pension benefits						Other benefits
December 31	2003		2002		2001		2003		2002		2001
Benefit obligation
Discount rate	6.25	%	6.75	%	7.25	%	6.25	%	6.75	%	7.25	%
Expected return on plan assets	9.0		9.0		10.0		9.0		9.0		10.0
Rate of compensation increase	4.6		4.6		4.6		4.6		4.6		4.6
Net periodic benefit cost (years ended)
Discount rate	6.75		7.25		7.5		6.75		7.25		7.5
Expected return on plan assets	9.0		10.0		10.0		9.0		10.0		10.0
Rate of compensation increase	4.6		4.6		4.6		4.6		4.6		4.6

At December 31, 2003, the assumed health care trend rates for 2004 and future years were as follows: medical, 10.00%, grading down to 4.25%; dental, 4.25%; and vision, 3.25%. At December 31, 2002, the assumed health care trend rates for 2003 and future years were as follows: medical, 9.28%, grading down to 4.25%; dental, 4.25%; and vision, 3.25%.

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

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

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

The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for pension plans with an accumulated benefit obligation in excess of plan assets were $3 million, $3 million and nil, respectively, as of December 31, 2003 and $3 million, $2 million and nil, respectively, as of December 31, 2002.

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

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would have increased the total service and interest cost by $0.3 million and the postretirement benefit obligation by $3.5 million, and a one-percentage-point decrease would have reduced the total service and interest cost by $0.3 million and the postretirement benefit obligation by $4.3 million.

11. Commitments and contingencies

Fuel contracts

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

Power purchase agreements (PPAs)

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

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

Interim increases

At December 31, 2003, HECO and its subsidiaries had recognized $16.6 million of revenues with respect to interim orders regarding certain integrated resource planning costs, which revenues are subject to refund, with interest, if and to the extent they exceed the amounts allowed in final orders.

HELCO power situation

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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Oahu transmission system

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

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

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

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

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

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

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

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

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

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

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

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

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

Environmental regulation

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

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

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

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

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

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

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

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

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

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

27

Collective bargaining agreements.

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

12. Regulatory restrictions on distributions to parent

At December 31, 2003, net assets (assets less liabilities and preferred stock) of approximately $449 million were not available for transfer to HEI in the form of dividends, loans or advances without regulatory approval.

13. Related-party transactions

HEI charged HECO and its subsidiaries $2.9 million, $2.2 million and $2.0 million for general management and administrative services in 2003, 2002 and 2001, respectively. The amounts charged by HEI to its subsidiaries are allocated primarily on the basis of actual labor hours expended in providing such services.

HEI also charged HECO nil, $2.1 million and $2.2 million for data processing services in 2003, 2002 and 2001, respectively.

HECO’s borrowings from HEI fluctuate during the year, and totaled $6.0 million and $5.6 million at December 31, 2003 and 2002, respectively. The interest charged on short-term borrowings from HEI is based on the rate HEI pays on its commercial paper, provided HEI’s commercial paper rating is equal to or better than HECO’s rating. If HEI’s commercial paper rating falls below HECO’s, interest is based on HECO’s short-term external borrowing rate, or quoted rates from the Wall Street Journal for 30-day dealer-placed commercial paper.

Interest charged by HEI to HECO totaled $0.1 million, $0.4 million and $1.2 million in 2003, 2002 and 2001, respectively.

14. Significant group concentrations of credit risk

HECO and its utility subsidiaries are regulated operating electric public utilities engaged in the generation, purchase, transmission, distribution and sale of electricity on the islands of Oahu, Hawaii, Maui, Lanai and Molokai in the State of Hawaii. HECO and its utility subsidiaries provide the only electric public utility service on the islands they serve. HECO and its utility subsidiaries grant credit to customers, all of whom reside or conduct business in the State of Hawaii.

15. Fair value of financial instruments

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

Cash and equivalents and short-term borrowings

The carrying amount approximated fair value because of the short maturity of these instruments.

Long-term debt

Fair value was estimated based on quoted market prices for the same or similar issues of debt.

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

Fair value was based on quoted market prices.

28

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

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

Limitations

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

29

16. Consolidating financial information (unaudited)

Consolidating balance sheet

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

30

Consolidating balance sheet

	December 31, 2002
(in thousands)	HECO			HELCO		MECO		HECO Capital Trust I	HECO Capital Trust II	Reclassifications and Eliminations		HECO Consolidated
Assets
Utility plant, at cost
Land	$	22,836		2,982		3,585		—	—	—		$	29,403
Plant and equipment		2,025,480		565,920		595,911		—	—	—			3,187,311
Less accumulated depreciation		(765,578	)	(222,360	)	(217,398	)	—	—	—			(1,205,336	)
Plant acquisition adjustment, net		—		—		302		—	—	—			302
Construction in progress		63,246		93,428		7,626		—	—	—			164,300
Net utility plant		1,345,984		439,970		390,026		—	—	—			2,175,980
Investment in wholly owned subsidiaries, at equity		355,869		—		—		—	—	(355,869	)[2]		—
Current assets
Cash and equivalents		9		4		1,713		—	—	—			1,726
Advances to affiliates		14,900		—		23,000		51,546	51,546	(140,992	)[1]		—
Customer accounts receivable, net		61,384		13,979		11,750		—	—	—			87,113
Accrued unbilled revenues, net		41,272		10,701		8,125		—	—	—			60,098
Other accounts receivable, net		2,582		411		462		—	—	(1,242	)[1]		2,213
Fuel oil stock, at average cost		25,701		3,446		6,502		—	—	—			35,649
Materials & supplies, at average cost		9,076		2,248		8,126		—	—	—			19,450
Prepayments and other		61,108		9,457		5,045		—	—	—			75,610
Total current assets		216,032		40,246		64,723		51,546	51,546	(142,234	)		281,859
Other assets
Unamortized debt expense		8,952		1,915		2,487		—	—	—			13,354
Long-term receivables and other		15,540		3,406		3,297		—	—	—			22,243
Total other assets		24,492		5,321		5,784		—	—	—			35,597
	$	1,942,377		485,537		460,533		51,546	51,546	(498,103	)	$	2,493,436
Capitalization and liabilities
Capitalization
Common stock equity	$	923,256		171,404		181,373		1,546	1,546	(355,869	)[2]	$	923,256
Cumulative preferred stock–not subject to mandatory redemption		22,293		7,000		5,000		—	—	—			34,293
HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO & HECO-guaranteed debentures		—		—		—		50,000	50,000	—			100,000
Long-term debt, net		495,689		140,993		171,680		—	—	(103,092	)[1]		705,270
Total capitalization		1,441,238		319,397		358,053		51,546	51,546	(458,961	)		1,762,819
Current liabilities
Short-term borrowings-affiliate		28,600		14,900		—		—	—	(37,900	)[1]		5,600
Accounts payable		41,594		10,462		7,936		—	—	—			59,992
Interest and preferred dividends payable		7,537		1,598		2,435		—	—	(38	) [1]		11,532
Taxes accrued		48,274		14,898		15,961		—	—	—			79,133
Other		20,998		3,679		4,547		—	—	(1,204	)[1]		28,020
Total current liabilities		147,003		45,537		30,879		—	—	(39,142	)		184,277
Deferred credits and other liabilities
Deferred income taxes		132,159		14,479		11,729		—	—	—			158,367
Regulatory liabilities		31,808		16,556		8,686		—	—	—			57,050
Unamortized tax credits		28,430		8,471		11,084		—	—	—			47,985
Other		23,441		26,809		14,594		—	—	—			64,844
Total deferred credits and other liabilities		215,838		66,315		46,093		—	—	—			328,246
Contributions in aid of construction		138,298		54,288		25,508		—	—	—			218,094
	$	1,942,377		485,537		460,533		51,546	51,546	(498,103	)	$	2,493,436

31

Consolidating statement of income

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

Consolidating statement of retained earnings

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

32

Consolidating statement of income

	Year ended December 31, 2002
(in thousands)	HECO			HELCO		MECO		HECO Capital Trust I	HECO Capital Trust II	Reclassifications and Eliminations		HECO Consolidated
Operating revenues	$	868,383		192,209		192,337		—	—	—		$	1,252,929
Operating expenses
Fuel oil		214,067		31,333		65,195		—	—	—			310,595
Purchased power		261,000		58,058		7,397		—	—	—			326,455
Other operation		83,190		21,697		27,023		—	—	—			131,910
Maintenance		41,411		13,437		11,693		—	—	—			66,541
Depreciation		63,613		19,548		22,263		—	—	—			105,424
Taxes, other than income taxes		83,089		18,424		18,605		—	—	—			120,118
Income taxes		37,380		7,899		11,450		—	—	—			56,729
		783,750		170,396		163,626		—	—	—			1,117,772
Operating income		84,633		21,813		28,711		—	—	—			135,157
Other income
Allowance for equity funds used during construction		3,514		217		223		—	—	—			3,954
Equity in earnings of subsidiaries		30,782		—		—		—	—	(30,782	)[2]		—
Other, net		3,172		342		84		4,149	3,763	(8,369	)[1]		3,141
		37,468		559		307		4,149	3,763	(39,151	)		7,095
Income before interest and other charges		122,101		22,372		29,018		4,149	3,763	(39,151	)		142,252
Interest and other charges
Interest on long-term debt		24,633		7,269		8,818		—	—	—			40,720
Amortization of net bond premium and expense		1,290		321		403		—	—	—			2,014
Preferred securities distributions of trust subsidiaries		—		—		—		—	—	7,675	[3]		7,675
Other interest charges		6,535		1,922		1,410		—	—	(8,369	)[1]		1,498
Allowance for borrowed funds used during construction		(1,642	)	(118	)	(95	)	—	—	—			(1,855	)
Preferred stock dividends of subsidiaries		—		—		—		—	—	915	[3]		915
		30,816		9,394		10,536		—	—	221			50,967
Income before preferred stock dividends of HECO		91,285		12,978		18,482		4,149	3,763	(39,372	)		91,285
Preferred stock dividends of HECO		1,080		534		381		4,025	3,650	(8,590	)[3]		1,080
Net income for common stock	$	90,205		12,444		18,101		124	113	(30,782	)	$	90,205

Consolidating statement of retained earnings

	Year ended December 31, 2002
(in thousands)	HECO			HELCO		MECO		HECO Capital Trust I		HECO Capital Trust II		Reclassifications and Eliminations		HECO Consolidated
Retained earnings, beginning of period	$	495,961		65,690		78,182		—		—		(143,872	)[2]	$	495,961
Net income for common stock		90,205		12,444		18,101		124		113		(30,782	)[2]		90,205
Common stock dividends		(44,143	)	(6,720	)	(9,191	)	(124	)	(113	)	16,148	[2]		(44,143	)
Retained earnings, end of period	$	542,023		71,414		87,092		—		—		(158,506	)	$	542,023

33

Consolidating statement of income

	Year ended December 31, 2001
(in thousands)	HECO			HELCO		MECO		HECO Capital Trust I	HECO Capital Trust II	Reclassifications and Eliminations		HECO Consolidated
Operating revenues	$	885,244		193,876		205,192		—	—	—		$	1,284,312
Operating expenses
Fuel oil		237,394		28,079		81,255		—	—	—			346,728
Purchased power		263,502		69,023		5,319		—	—	—			337,844
Other operation		80,825		19,181		25,559		—	—	—			125,565
Maintenance		39,258		9,444		13,099		—	—	—			61,801
Depreciation		60,799		18,522		21,393		—	—	—			100,714
Taxes, other than income taxes		83,310		18,315		19,269		—	—	—			120,894
Income taxes		35,774		8,362		11,298		—	—	—			55,434
		800,862		170,926		177,192		—	—	—			1,148,980
Operating income		84,382		22,950		28,000		—	—	—			135,332
Other income
Allowance for equity funds used during construction		3,506		286		447		—	—	—			4,239
Equity in earnings of subsidiaries		31,097		—		—		—	—	(31,097	)[2]		—
Other, net		3,447		486		210		4,149	3,763	(8,858	)[1]		3,197
		38,050		772		657		4,149	3,763	(39,955	)		7,436
Income before interest and other charges		122,432		23,722		28,657		4,149	3,763	(39,955	)		142,768
Interest and other charges
Interest on long-term debt		23,850		7,628		8,818		—	—	—			40,296
Amortization of net bond premium and expense		1,310		346		407		—	—	—			2,063
Preferred securities distributions of trust subsidiaries		—		—		—		—	—	7,675	[3]		7,675
Other interest charges		9,775		2,411		1,369		—	—	(8,858	)[1]		4,697
Allowance for borrowed funds used during construction		(1,883	)	(174	)	(201	)	—	—	—			(2,258	)
Preferred stock dividends of subsidiaries		—		—		—		—	—	915	[3]		915
		33,052		10,211		10,393		—	—	(268	)		53,388
Income before preferred stock dividends of HECO		89,380		13,511		18,264		4,149	3,763	(39,687	)		89,380
Preferred stock dividends of HECO		1,080		534		381		4,025	3,650	(8,590	)[3]		1,080
Net income for common stock	$	88,300		12,977		17,883		124	113	(31,097	)	$	88,300

Consolidating statement of retained earnings

	Year ended December 31, 2001
(in thousands)	HECO			HELCO		MECO		HECO Capital Trust I		HECO Capital Trust II		Reclassifications and Eliminations		HECO Consolidated
Retained earnings, beginning of period	$	443,970		62,962		73,586		—		—		(136,548	)[2]	$	443,970
Net income for common stock		88,300		12,977		17,883		124		113		(31,097	)[2]		88,300
Common stock dividends		(36,309	)	(10,249	)	(13,287	)	(124	)	(113	)	23,773	[2]		(36,309	)
Retained earnings, end of period	$	495,961		65,690		78,182		—		—		(143,872	)	$	495,961

34

Consolidating statement of cash flows

	Year ended December 31, 2003
(in thousands)	HECO			HELCO		MECO		Renewable Hawaii, Inc.		HECO Capital Trust I		HECO Capital Trust II		Elimination addition to (deduction from) cash flows		HECO Consolidated
Cash flows from operating activities:
Income before preferred stock dividends of HECO	$	79,991		11,683		18,588		(134	)	4,149		3,763		(38,049	)[2]	$	79,991
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Equity in earnings		(29,459	)	—		—		—		—		—		29,459	[2]		—
Common stock dividends received from subsidiaries		20,561		—		—		—		—		—		(20,561	)[2]		—
Depreciation of property, plant and equipment		67,121		20,293		23,146		—		—		—		—			110,560
Other amortization		3,973		772		3,487		—		—		—		—			8,232
Deferred income taxes		5,804		5,599		1,116		—		—		—		—			12,519
Tax credits, net		292		388		(95	)	—		—		—		—			585
Allowance for equity funds used during construction		(3,652	)	(170	)	(445	)	—		—		—		—			(4,267	)
Changes in assets and liabilities:
Increase in accounts receivable		(1,291	)	(2,441	)	(926	)	—		—		—		(348	)[1]		(5,006	)
Decrease (increase) in accrued unbilled revenues		72		4		(350	)	—		—		—		—			(274	)
Increase in fuel oil stock		(6,359	)	(80	)	(1,524	)	—		—		—		—			(7,963	)
Increase in materials and supplies		(1,255	)	(288	)	(240	)	—		—		—		—			(1,783	)
Increase in regulatory assets		(1,550	)	(209	)	(3,138	)	—		—		—		—			(4,897	)
Increase in accounts payable		7,829		131		4,425		—		—		—		—			12,385
Increase in taxes accrued		10,288		1,625		2,257		—		—		—		—			14,170
Changes in other assets and liabilities		(14,835	)	(909	)	(486	)	11		—		—		8,023	[2]		(8,196	)
Net cash provided by (used in) operating activities		137,530		36,398		45,815		(123	)	4,149		3,763		(21,476	)		206,056
Cash flows from investing activities:
Capital expenditures		(91,232	)	(29,426	)	(26,306	)	—		—		—		—			(146,964	)
Contributions in aid of construction		6,185		4,629		2,149		—		—		—		—			12,963
Advances from (to) affiliates		4,100		—		(2,500	)	—		—		—		(1,600	)[1]		—
Investment in subsidiary		(181	)	—		—		—		—		—		181	[2]		—
Proceeds from sales of assets		118		—		—		—		—		—		—			118
Net cash used in investing activities		(81,010	)	(24,797	)	(26,657	)	—		—		—		(1,419	)		(133,883	)
Cash flows from financing activities:
Common stock dividends		(57,719	)	(7,934	)	(12,390	)	—		(124	)	(113	)	20,561	[2]		(57,719	)
Preferred stock dividends		(1,080	)	(534	)	(381	)	—		—		—		915	[2]		(1,080	)
Preferred securities distributions of trust subsidiaries		—		—		—		—		(4,025	)	(3,650	)	—			(7,675	)
Proceeds from issuance of common stock		—		—		—		181		—		—		(181	)[2]		—
Proceeds from issuance of long-term debt		42,098		25,837		—		—		—		—		—			67,935
Repayment of long-term debt		(40,000	)	(26,000	)	(8,000	)	—		—		—		—			(74,000	)
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		2,900		(4,100	)	—		—		—		—		1,600	[1]		400
Other		(2,719	)	1,130		(13	)	—		—		—		—			(1,602	)
Net cash provided by (used in) financing activities		(56,520	)	(11,601	)	(20,784	)	181		(4,149	)	(3,763	)	22,895			(73,741	)
Net increase (decrease) in cash and equivalents		—		—		(1,626	)	58		—		—		—			(1,568	)
Cash and equivalents, beginning of year		9		4		1,713		—		—		—		—			1,726
Cash and equivalents, end of year	$	9		4		87		58		—		—		—		$	158

35

Consolidating statement of cash flows

	Year ended December 31, 2002
(in thousands)	HECO			HELCO		MECO		HECO Capital Trust I		HECO Capital Trust II		Elimination addition to (deduction from) cash flows		HECO Consolidated
Cash flows from operating activities:
Income before preferred stock dividends of HECO	$	91,285		12,978		18,482		4,149		3,763		(39,372	)[2]	$	91,285
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Equity in earnings		(30,782	)	—		—		—		—		30,782	[2]		—
Common stock dividends received from subsidiaries		16,148		—		—		—		—		(16,148	)[2]		—
Depreciation of property, plant and equipment		63,613		19,548		22,263		—		—		—			105,424
Other amortization		3,949		1,873		5,554		—		—		—			11,376
Deferred income taxes		9,118		2,495		1,205		—		—		—			12,818
Tax credits, net		953		61		17		—		—		—			1,031
Allowance for equity funds used during construction		(3,514	)	(217	)	(223	)	—		—		—			(3,954	)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable		(5,202	)	(249	)	141		—		—		508	[1]		(4,802	)
Decrease (increase) in accrued unbilled revenues		(6,200	)	(1,846	)	571		—		—		—			(7,475	)
Increase in fuel oil stock		(9,861	)	(439	)	(909	)	—		—		—			(11,209	)
Decrease (increase) in materials and supplies		92		(266	)	426		—		—		—			252
Decrease (increase) in regulatory assets		112		418		(2,411	)	—		—		—			(1,881	)
Increase (decrease) in accounts payable		6,734		354		(1,062	)	—		—		—			6,026
Decrease in taxes accrued		(3,942	)	(943	)	(2,040	)	—		—		—			(6,925	)
Changes in other assets and liabilities		(25,264	)	(1,220	)	(1,072	)	—		—		7,167	[2]		(20,389	)
Net cash provided by operating activities		107,239		32,547		40,942		4,149		3,763		(17,063	)		171,577
Cash flows from investing activities:
Capital expenditures		(71,316	)	(27,541	)	(15,701	)	—		—		—			(114,558	)
Contributions in aid of construction		6,042		3,518		1,482		—		—		—			11,042
Advances to affiliates		(2,300	)	—		(16,000	)	—		—		18,300	[1]		—
Proceeds from sales of assets		56		—		—		—		—		—			56
Net cash used in investing activities		(67,518	)	(24,023	)	(30,219	)	—		—		18,300			(103,460	)
Cash flows from financing activities:
Common stock dividends		(44,143	)	(6,720	)	(9,191	)	(124	)	(113	)	16,148	[2]		(44,143	)
Preferred stock dividends		(1,080	)	(534	)	(381	)	—		—		915	[2]		(1,080	)
Preferred securities distributions of trust subsidiaries		—		—		—		(4,025	)	(3,650	)	—			(7,675	)
Proceeds from issuance of long-term debt		35,275		—		—		—		—		—			35,275
Repayment of long-term debt		—		(5,000	)	—		—		—		—			(5,000	)
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		(26,697	)	2,300		—		—		—		(18,300	)[1]		(42,697	)
Other		(3,076	)	152		(5	)	—		—		—			(2,929	)
Net cash used in financing activities		(39,721	)	(9,802	)	(9,577	)	(4,149	)	(3,763	)	(1,237	)		(68,249	)
Net increase (decrease) in cash and equivalents		—		(1,278	)	1,146		—		—		—			(132	)
Cash and equivalents, beginning of year		9		1,282		567		—		—		—			1,858
Cash and equivalents, end of year	$	9		4		1,713		—		—		—		$	1,726

36

Consolidating statement of cash flows

	Year ended December 31, 2001
(in thousands)	HECO			HELCO		MECO		HECO Capital Trust I		HECO Capital Trust II		Elimination addition to (deduction from) cash flows		HECO Consolidated
Cash flows from operating activities:
Income before preferred stock dividends of HECO	$	89,380		13,511		18,264		4,149		3,763		(39,687	)[2]	$	89,380
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Equity in earnings		(31,097	)	—		—		—		—		31,097	[2]		—
Common stock dividends received from subsidiaries		23,773		—		—		—		—		(23,773	)[2]		—
Depreciation of property, plant and equipment		60,799		18,522		21,393		—		—		—			100,714
Other amortization		5,157		2,054		5,529		—		—		—			12,740
Deferred income taxes		6,471		1,448		638		—		—		—			8,557
Tax credits, net		1,429		(95	)	1,142		—		—		—			2,476
Allowance for equity funds used during construction		(3,506	)	(286	)	(447	)	—		—		—			(4,239	)
Changes in assets and liabilities:
Decrease in accounts receivable.		6,031		1,801		918		—		—		698	[1]		9,448
Decrease in accrued unbilled revenues		9,376		1,289		732		—		—		—			11,397
Decrease in fuel oil stock		8,336		432		3,916		—		—		—			12,684
Decrease (increase) in materials and supplies		(2,210	)	383		(1,088	)	—		—		—			(2,915	)
Increase in regulatory assets		(1,212	)	(255	)	(2,569	)	—		—		—			(4,036	)
Decrease in accounts payable		(16,389	)	(38	)	(1,305	)	—		—		—			(17,732	)
Increase in taxes accrued		6,122		269		1,481		—		—		—			7,872
Changes in other assets and liabilities		(29,548	)	(2,373	)	(2,653	)	—		—		6,977	[2]		(27,597	)
Net cash provided by operating activities		132,912		36,662		45,951		4,149		3,763		(24,688	)		198,749
Cash flows from investing activities:
Capital expenditures		(69,353	)	(20,503	)	(25,684	)	—		—		—			(115,540	)
Contributions in aid of construction		4,343		4,279		2,336		—		—		—			10,958
Advances to affiliates		9,200		—		(7,000	)	—		—		(2,200	)[1]		—
Net cash used in investing activities		(55,810	)	(16,224	)	(30,348	)	—		—		(2,200	)		(104,582	)
Cash flows from financing activities:
Common stock dividends		(36,309	)	(10,249	)	(13,287	)	(124	)	(113	)	23,773	[2]		(36,309	)
Preferred stock dividends		(1,080	)	(534	)	(381	)	—		—		915	[2]		(1,080	)
Preferred securities distributions of trust subsidiaries		—		—		—		(4,025	)	(3,650	)	—			(7,675	)
Proceeds from issuance of long-term debt		17,336		—		—		—		—		—			17,336
Net decrease in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		(54,869	)	(7,700	)	(1,500	)	—		—		2,200	[1]		(61,869	)
Repayment of other short-term borrowings		(3,000	)	—		—		—		—		—			(3,000	)
Other		(569	)	(677	)	—		—		—		—			(1,246	)
Net cash used in financing activities		(78,491	)	(19,160	)	(15,168	)	(4,149	)	(3,763	)	26,888			(93,843	)
Net increase (decrease) in cash and equivalents		(1,389	)	1,278		435		—		—		—			324
Cash and equivalents, beginning of year		1,398		4		132		—		—		—			1,534
Cash and equivalents, end of year	$	9		1,282		567		—		—		—		$	1,858

37

Explanation of reclassifications and eliminations on consolidating schedules

[1] Eliminations of intercompany receivables and payables and other intercompany transactions.

[2] Elimination of investment in subsidiaries, carried at equity.

[3] Reclassification of preferred stock dividends of Hawaii Electric Light Company, Inc. and Maui Electric Company, Limited and of preferred securities distributions of HECO Capital Trust I and HECO Capital Trust II for financial statement presentation.

HECO has not provided separate financial statements and other disclosures concerning HELCO and MECO because management has concluded that such financial statements and other information are not material to holders of the trust preferred securities issued by HECO Capital Trust I and HECO Capital Trust II, which trusts hold the 1997 and 1998 junior deferrable debentures issued by HELCO and MECO, which debentures have been fully and unconditionally guaranteed by HECO.

17. Consolidated quarterly financial information (unaudited)

Selected quarterly consolidated financial information of the Company for 2003 and 2002 follows:

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

	Quarters ended								Year ended Dec. 31
2002	March 31		June 30		Sept. 30		Dec. 31
(in thousands)
Operating revenues	$	277,333	$	306,616	$	332,453	$	336,527	$	1,252,929
Operating income		31,921		35,082		36,512		31,642		135,157
Net income for common stock		20,359		23,850		25,610		20,386		90,205

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

38

Independent Auditors’ Report

To the Board of Directors and Stockholder

Hawaiian Electric Company, Inc.:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Hawaiian Electric Company, Inc. (a wholly-owned subsidiary of Hawaiian Electric Industries, Inc.) and subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of income, retained earnings and cash flows for each of the years in the three-year period ended December 31, 2003. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Hawaiian Electric Company, Inc. and subsidiaries as of December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

/s/ KPMG LLP

Honolulu, Hawaii

February 11, 2004

39