HECO Exhibit 99

Selected Financial Data

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31	2005			2004			2003			2002			2001
(in thousands)
Income statement data
Operating revenues	$	1,801,710		$	1,546,875		$	1,393,038		$	1,252,929		$	1,284,312
Operating expenses		1,688,168			1,425,583			1,268,200			1,117,772			1,148,980
Operating income		113,542			121,292			124,838			135,157			135,332
Other income		8,643			8,926			6,170			7,095			7,436
Income before interest and other charges		122,185			130,218			131,008			142,252			142,768
Interest and other charges		48,303			47,961			51,017			50,967			53,388
Income before preferred stock dividends of HECO		73,882			82,257			79,991			91,285			89,380
Preferred stock dividends of HECO		1,080			1,080			1,080			1,080			1,080
Net income for common stock	$	72,802		$	81,177		$	78,911		$	90,205		$	88,300
At December 31	2005			2004			2003			2002			2001
(in thousands)
Balance sheet data
Utility plant	$	3,930,321		$	3,709,857		$	3,531,299		$	3,381,316		$	3,270,855
Accumulated depreciation		(1,456,537	)		(1,361,703	)		(1,290,929	)		(1,205,336	)		(1,120,858	)
Net utility plant	$	2,473,784		$	2,348,154		$	2,240,370		$	2,175,980		$	2,149,997
Total assets	$	3,081,461		$	2,879,615		$	2,687,798		$	2,599,004		$	2,535,212
Capitalization:1
Short-term borrowings from non-affiliates and affiliate	$	136,165		$	88,568		$	6,000		$	5,600		$	48,297
Long-term debt, net		765,993			752,735			699,420			705,270			685,269
Preferred stock not subject to mandatory redemption		34,293			34,293			34,293			34,293			34,293
HECO-obligated preferred securities of subsidiary trusts		—			—			100,000			100,000			100,000
Common stock equity		1,039,259			1,017,104			944,443			923,256			877,154
Total capitalization	$	1,975,710		$	1,892,700		$	1,784,156		$	1,768,419		$	1,745,013
Capital structure ratios (%)1
Debt		45.7			44.5			39.6			40.2			42.0
Preferred stock		1.7			1.8			1.9			1.9			2.0
HECO-obligated preferred securities of subsidiary trusts		—			—			5.6			5.7			5.7
Common stock equity		52.6			53.7			52.9			52.2			50.3

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

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

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

1

Annual Report of Management on Internal Control Over Financial Reporting

The Board of Directors and Shareholder

Hawaiian Electric Company, Inc.:

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934, as amended. The Company’s internal control system was designed to provide reasonable assurance to management and the Board of Directors regarding the preparation and fair presentation of its consolidated financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005 based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management has concluded that the Company’s internal control over financial reporting was effective as of December 31, 2005.

KPMG LLP, an independent registered public accounting firm, has issued an audit report on management’s assessment of the Company’s internal control over financial reporting as of December 31, 2005. This report appears on page 3.

/s/ T. Michael May	/s/ Tayne S. Y. Sekimura	/s/ Patsy H. Nanbu
T. Michael May President and Chief Executive Officer	Tayne S. Y. Sekimura Financial Vice President and Chief Financial Officer	Patsy H. Nanbu Controller and Chief Accounting Officer

March 6, 2006

2

Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting

The Board of Directors and Shareholder

Hawaiian Electric Company, Inc.:

We have audited management’s assessment, included in the accompanying annual report of management on internal control over financial reporting, that Hawaiian Electric Company, Inc. maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Hawaiian Electric Company, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that Hawaiian Electric Company, Inc. maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the COSO. Also, in our opinion, Hawaiian Electric Company, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets and statements of capitalization of Hawaiian Electric Company, Inc. and subsidiaries as of December 31, 2005 and 2004, 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, 2005, and our report dated March 6, 2006 expressed an unqualified opinion on those consolidated financial statements and referred to the adoption of Financial Accounting Standards Board Interpretation No. 46(R), Consolidation of Variable Interest Entities.

/s/ KPMG LLP

Honolulu, Hawaii

March 6, 2006

3

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholder

Hawaiian Electric Company, Inc.:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Hawaiian Electric Company, Inc. and subsidiaries as of December 31, 2005 and 2004, 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, 2005. 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 the standards of the Public Company Accounting Oversight Board (United States). 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, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.

As discussed in Notes 1 and 3 to consolidated financial statements, effective January 1, 2004, the Company adopted Financial Accounting Standards Board Interpretation No. 46(R), Consolidation of Variable Interest Entities.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Hawaiian Electric Company, Inc.’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 6, 2006 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

/s/ KPMG LLP

Honolulu, Hawaii

March 6, 2006

4

Consolidated Financial Statements

Consolidated Statements of Income

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31	2005			2004			2003
(in thousands)
Operating revenues	$	1,801,710		$	1,546,875		$	1,393,038
Operating expenses
Fuel oil		639,650			483,423			388,560
Purchased power		458,120			398,836			368,076
Other operation		172,962			157,198			155,531
Maintenance		82,242			77,313			64,621
Depreciation		122,870			114,920			110,560
Taxes, other than income taxes		167,295			143,834			130,677
Income taxes		45,029			50,059			50,175
		1,688,168			1,425,583			1,268,200
Operating income		113,542			121,292			124,838
Other income
Allowance for equity funds used during construction		5,105			5,794			4,267
Other, net		3,538			3,132			1,903
		8,643			8,926			6,170
Income before interest and other charges		122,185			130,218			131,008
Interest and other charges
Interest on long-term debt		43,063			42,543			40,698
Amortization of net bond premium and expense		2,212			2,289			2,131
Preferred securities distributions of trust subsidiaries		—			—			7,675
Other interest charges		4,133			4,756			1,512
Allowance for borrowed funds used during construction		(2,020	)		(2,542	)		(1,914	)
Preferred stock dividends of subsidiaries		915			915			915
		48,303			47,961			51,017
Income before preferred stock dividends of HECO		73,882			82,257			79,991
Preferred stock dividends of HECO		1,080			1,080			1,080
Net income for common stock	$	72,802		$	81,177		$	78,911

Consolidated Statements of Retained Earnings

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31	2005			2004			2003
(in thousands)
Retained earnings, January 1	$	632,779		$	563,215		$	542,023
Net income for common stock		72,802			81,177			78,911
Common stock dividends		(50,895	)		(11,613	)		(57,719	)
Retained earnings, December 31	$	654,686		$	632,779		$	563,215

See accompanying “Notes to Consolidated Financial Statements.”

5

Consolidated Balance Sheets

Hawaiian Electric Company, Inc. and Subsidiaries

December 31	2005			2004
(in thousands)
Assets
Utility plant, at cost
Land	$	33,034		$	32,995
Plant and equipment		3,749,386			3,573,716
Less accumulated depreciation		(1,456,537	)		(1,361,703	)
Plant acquisition adjustment, net		145			197
Construction in progress		147,756			102,949
Net utility plant		2,473,784			2,348,154
Current assets
Cash and equivalents		143			327
Customer accounts receivable, net		123,895			102,007
Accrued unbilled revenues, net		91,321			79,028
Other accounts receivable, net		14,761			6,499
Fuel oil stock, at average cost		85,450			58,570
Materials and supplies, at average cost		26,974			23,768
Prepayments and other		114,902			114,345
Total current assets		457,446			384,544
Other long-term assets
Regulatory assets		110,718			108,630
Unamortized debt expense		14,361			14,724
Other		25,152			23,563
Total other long-term assets		150,231			146,917
	$	3,081,461		$	2,879,615
Capitalization and liabilities
Capitalization (see Consolidated Statements of Capitalization)
Common stock equity	$	1,039,259		$	1,017,104
Cumulative preferred stock, not subject to mandatory redemption		34,293			34,293
Long-term debt, net		765,993			752,735
Total capitalization		1,839,545			1,804,132
Current liabilities
Short-term borrowings-nonaffiliates		136,165			76,611
Short-term borrowings-affiliate		—			11,957
Accounts payable		122,201			94,015
Interest and preferred dividends payable		9,990			10,738
Taxes accrued		133,583			105,925
Other		37,132			34,981
Total current liabilities		439,071			334,227
Deferred credits and other liabilities
Deferred income taxes		208,374			189,193
Regulatory liabilities		219,204			197,089
Unamortized tax credits		55,327			53,208
Other		63,677			66,261
Total deferred credits and other liabilities		546,582			505,751
Contributions in aid of construction		256,263			235,505
	$	3,081,461		$	2,879,615

See accompanying “Notes to Consolidated Financial Statements.”

6

Consolidated Statements of Capitalization

Hawaiian Electric Company, Inc. and Subsidiaries

December 31	2005		2004		2003
(dollars in thousands, except par value)
Common stock equity
Common stock of $6 2/3 par value Authorized: 50,000,000 shares. Outstanding: 2005, 2004 and 2003, 12,805,843 shares	$	85,387	$	85,387	$	85,387
Premium on capital stock		299,186		298,938		295,841
Retained earnings		654,686		632,779		563,215
Common stock equity		1,039,259		1,017,104		944,443
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: 2005 and 2004, 1,234,657 shares.

Series	Par Value				Shares Outstanding December 31, 2005 and 2004	2005		2004
(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.”

7

Consolidated Statements of Capitalization, continued

Hawaiian Electric Company, Inc. and Subsidiaries

December 31	2005		2004
(in thousands)
Long-term debt
Obligations to the State of Hawaii for the repayment of Special Purpose Revenue Bonds:
HECO, 4.80%, refunding series 2005A, due 2025	$	40,000	$	—
HELCO, 4.80% refunding series 2005A, due 2025		5,000		—
MECO, 4.80%, refunding series 2005A, due 2025		2,000		—
HECO, 5.00%, refunding series 2003B, due 2022		40,000		40,000
HELCO, 5.00%, refunding series 2003B, due 2022		12,000		12,000
HELCO, 4.75%, refunding series 2003A, due 2020		14,000		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, refunded in 2005		—		40,000
HELCO, 6.60%, series 1995A, refunded in 2005		—		5,000
MECO, 6.60%, series 1995A, refunded in 2005		—		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
		717,900		717,900
Less funds on deposit with trustees		—		12,462
Total obligations to the State of Hawaii		717,900		705,438
Other long-term debt – unsecured:
6.50 %, series 2004, Junior subordinated deferrable interest debentures, due 2034		51,546		51,546
Total long-term debt		769,446		756,984
Less unamortized discount		3,453		4,249
Long-term debt, net		765,993		752,735
Total capitalization	$	1,839,545	$	1,804,132

See accompanying “Notes to Consolidated Financial Statements.”

8

Consolidated Statements of Cash Flows

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31	2005			2004			2003
(in thousands)
Cash flows from operating activities
Income before preferred stock dividends of HECO	$	73,882		$	82,257		$	79,991
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Depreciation of utility plant		122,870			114,920			110,560
Other amortization		8,479			8,780			8,232
Deferred income taxes		19,086			20,784			12,519
Tax credits, net		3,471			5,212			585
Allowance for equity funds used during construction		(5,105	)		(5,794	)		(4,267	)
Changes in assets and liabilities:
Increase in accounts receivable		(30,150	)		(14,174	)		(5,006	)
Increase in accrued unbilled revenues		(12,293	)		(18,656	)		(274	)
Increase in fuel oil stock		(26,880	)		(14,958	)		(7,963	)
Increase in materials and supplies		(3,206	)		(2,535	)		(1,783	)
Increase in regulatory assets		(5,036	)		(2,424	)		(4,897	)
Increase in accounts payable		28,186			21,638			12,385
Increase in taxes accrued		27,658			12,622			14,170
Increase in prepaid pension benefit cost		(300	)		(25,097	)		(10,723	)
Other		(15,944	)		(13,725	)		2,527
Net cash provided by operating activities		184,718			168,850			206,056
Cash flows from investing activities
Capital expenditures		(217,610	)		(201,236	)		(146,964	)
Contributions in aid of construction		21,083			8,522			12,963
Investment in unconsolidated subsidiary		—			(1,546	)		—
Distributions from unconsolidated subsidiaries		—			3,093			—
Proceeds from sales of assets		1,680			650			118
Net cash used in investing activities		(194,847	)		(190,517	)		(133,883	)
Cash flows from financing activities
Common stock dividends		(50,895	)		(11,613	)		(57,719	)
Preferred stock dividends		(1,080	)		(1,080	)		(1,080	)
Preferred securities distributions of trust subsidiaries		—			—			(7,675	)
Proceeds from issuance of long-term debt		59,462			53,097			67,935
Repayment of long-term debt		(47,000	)		(103,093	)		(74,000	)
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		47,597			82,568			400
Other		1,861			1,957			(1,602	)
Net cash provided by (used in) financing activities		9,945			21,836			(73,741	)
Net increase (decrease) in cash and equivalents		(184	)		169			(1,568	)
Cash and equivalents, January 1		327			158			1,726
Cash and equivalents, December 31	$	143		$	327		$	158

See accompanying “Notes to Consolidated Financial Statements.”

9

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 and HECO Capital Trust III, which is an unconsolidated financing entity.

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; revenues; and variable interest entities (VIEs).

Consolidation

The consolidated financial statements include the accounts of HECO and its subsidiaries (collectively, the Company), but exclude subsidiaries which are variable-interest entities of which the Company is not the primary beneficiary. Investments in companies over which the Company has the ability to exercise significant influence, but not control, are accounted for using the equity method. The Company is a wholly-owned subsidiary of Hawaiian Electric Industries, Inc. (HEI). All material intercompany accounts and transactions have been eliminated in consolidation.

Consolidation of VIEs. In December 2003, the Financial Accounting Standards Board (FASB) issued Interpretation No. (FIN) 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.

As of December 31, 2005, the Company had six purchase power agreements (PPAs) for a total of 540 MW of firm capacity, and other PPAs with smaller independent power producers (IPPs) and Schedule Q providers that supplied as-available energy. Approximately 91% of the 540 MW of firm capacity is under PPAs, entered into before December 31, 2003, with AES Hawaii, Inc. (AES Hawaii), Kalaeloa Partners, L.P. (Kalaeloa), Hamakua Energy Partners, L.P. (HEP) and HPower. Purchases from all IPPs for 2005 totaled $458 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPower totaling $137 million, $169 million, $63 million and $33 million, respectively. The primary business activities of these IPPs are the generation and sale of power to the Company (and municipal waste disposal in the case of HPower). Current financial information about the size, including total assets and revenues, for many of these IPPs is not publicly available. Under FIN 46R, an enterprise with an interest in a VIE or potential VIE created before December 31, 2003 (and not thereafter materially modified) is not required to apply FIN 46R to that entity if the enterprise is unable to obtain, after making an exhaustive effort, the necessary information.

The Company has reviewed its significant PPAs and determined that the IPPs had no contractual obligation to provide such information. In March 2004, the Company sent letters to all of their IPPs, except the Schedule Q providers, requesting the information that they need to determine the applicability of FIN 46R to the respective IPP, and subsequently contacted most of the IPPs by telephone to explain and repeat its

10

request for information. (The Company excluded their Schedule Q providers from the scope of FIN 46R because its variable interest in the provider would not be significant to the Company and they did not participate significantly in the design of the provider.) Some of the IPPs provided sufficient information for the Company to determine that the IPP was not a VIE, or was either a “business” or “governmental organization” (HPower) as defined under FIN 46R, and thus excluded from the scope of FIN 46R. Other IPPs, including the three largest, declined to provide the information necessary for the Company to determine the applicability of FIN 46R, and the Company was unable to apply FIN 46R to these IPPs. In January 2005 the Company again sent letters to the IPPs that were not excluded from the scope of FIN 46R, requesting the information required to determine the applicability of FIN 46R to the respective IPP. All of these IPPs again declined to provide the necessary information. Kalaeloa has since provided its information (see below).

As required under FIN 46R, the Company has continued its efforts to obtain from the IPPs the information necessary to make the determinations required under FIN 46R. If the requested information is ultimately received, a possible outcome of future analysis is the consolidation of an IPP in HECO’s consolidated financial statements. The consolidation of any significant IPP could have a material effect on HECO’s consolidated financial statements, including the recognition of a significant amount of assets and liabilities, and, if such a consolidated IPP were operating at a loss and had insufficient equity, the potential recognition of such losses.

In October 2004, Kalaeloa and HECO executed two amendments to their PPA, under which Kalaeloa would make available additional firm capacity to HECO. The amendments became effective when the costs of the additional capacity and purchased power were included in HECO’s rates as a result of an Interim D&O issued in HECO’s current rate case. The additional firm capacity to be provided by Kalaeloa is 28 MW. Kalaeloa provided HECO the information HECO needed to complete its determination of whether Kalaeloa is a variable interest entity, and, whether HECO is the primary beneficiary. While it has been determined that Kalaeloa is a variable interest entity, HECO has concluded that it is not the primary beneficiary of that entity and accordingly Kalaeloa need not be consolidated in HECO’s consolidated financial statements. See Note 3 for additional information regarding the application of FIN 46R to Kalaeloa.

In October 2004, HELCO and Apollo Energy Corporation (Apollo) executed a restated and amended PPA which enables Apollo to repower its 7 MW facility, and install additional capacity, for a total windfarm allowed capacity of 20 MW. Due to problems with its wind turbine supplier, however, Apollo is claiming an event of force majeure under the PPA and the project may be delayed. In December 2004, MECO executed a new PPA with Kaheawa Wind Power, LLC (KWP), which is installing a 30 MW windfarm on Maui. The revised PPA with Apollo and new PPA with KWP were approved by the PUC in March 2005, and became effective in April 2005. The PPAs require Apollo and KWP to provide information necessary to (1) determine if HELCO and MECO must consolidate Apollo and KWP, respectively, under FIN 46R, (2) consolidate Apollo and/or KWP, if necessary under FIN 46R, and (3) comply with Section 404 of Sarbanes-Oxley Act of 2002 (SOX). Management is in the process of obtaining the information necessary to complete its determination of whether Apollo or KWP are VIEs and, if so, whether HELCO or MECO, respectively, is the primary beneficiary. Based on information currently available, management believes the impact on consolidated HECO’s financial statements of the consolidation of Apollo and/or KWP, if necessary, would not be material. However, depending on the magnitude of the improvements contemplated in the PPAs, the impact of a required consolidation of Apollo and KWP could be material in the future. If required to consolidated the financial statements of Apollo and/or KWP in the future and such consolidation had a material effect, HECO would retrospectively apply FIN 46R in accordance with SFAS No. 154 “Accounting Changes and Error Corrections.”

See Note 3 for additional information regarding the application of FIN 46R.

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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 its operations currently satisfy the SFAS No. 71 criteria. If events or circumstances should change so that those criteria are no longer satisfied, the Company expects that the regulatory assets would be charged to income and the regulatory liabilities would be credited to income or refunded to ratepayers. 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 for regulatory liabilities or if regulatory liabilities are required to be refunded to ratepayers. See Note 6 for additional information regarding regulatory assets and liabilities.

Equity method

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

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. Costs for betterments that make property, plant or equipment more useful, more efficient, of greater durability or of greater capacity are also capitalized. Upon the retirement or sale of electric utility plant, generally 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.

In the future, if a PPA falls within the scope of Emerging Issues Task Force (EITF) Issue No. 01-8, “Determining Whether an Arrangement Contains a Lease” and results in the classification of the agreement as a capital lease, the Company would recognize a capital asset and a lease obligation.

Depreciation

Depreciation is computed primarily using the straight-line method over the estimated lives of the assets being depreciated. Utility plant additions in the current year are depreciated beginning January 1 of the following year. Utility plant has lives ranging from 20 to 45 years for production plant, from 25 to 60 years for transmission and distribution plant and from 7 to 45 years for general plant. The composite annual depreciation rate, which includes a component for cost of removal, was 3.9% in 2005, 2004 and 2003.

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.

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Accounts receivable

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

Retirement benefits

Pension and other postretirement benefit costs/(returns) are charged/(credited) primarily to expense and electric utility plant. The PUC requires the Company to fund its pension and postretirement benefit costs. The Company’s policy is to fund qualified pension plan 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 “Employers’ Accounting for Pensions” 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 “Employers’ Accounting for Postretirement Benefits Other Than Pensions” 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, contributions are amortized on a straight-line basis over 30 years as an offset against depreciation expense.

Electric utility revenues

Electric utility revenues are based on rates authorized by the PUC and include revenues applicable to energy consumed in the accounting period but not yet billed to the customers. Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers for billing purposes is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on the 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. As of December 31, 2005, customer accounts receivable include unbilled energy revenues of $91 million on a base of annual revenue of $1.8 billion. Revenue amounts recorded pursuant to a PUC interim order are subject to refund, with interest, pending a final order.

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The rate schedules of HECO, HELCO and MECO include energy cost adjustment clauses under which electric rates are adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power. In 2004 PUC decisions approving their fuel supply contracts, the PUC affirmed HECO, HELCO and MECO’s right to include in their respective energy cost adjustment clauses the stated costs incurred pursuant to their respective new fuel supply contracts, to the extent that these costs are not included in their respective base rates, and restated its intention to examine the need for continued use of energy cost adjustment clauses in rate cases.

The Company’s operating revenues include amounts for various revenue taxes. Revenue taxes are recorded as an expense in the year the related revenues are recognized. Payments to the taxing authorities by the Company are based on the prior years’ revenues. For 2005, 2004 and 2003, the Company included approximately $159 million, $136 million and $123 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

Repairs and maintenance costs

Repairs and maintenance costs for overhauls of generating units are generally expensed as they are incurred.

Allowance for Funds Used During Construction (AFUDC)

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

The weighted-average AFUDC rate was 8.5% in 2005, 8.6% in 2004 and 8.7% in 2003, 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.

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 might be impaired and written down or written off.

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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

Other-than-temporary impairment and its application to certain investments. In March 2004, FASB ratified EITF Issue No. 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments.” EITF Issue No. 03-1 provides guidance for determining whether an investment in debt or equity securities is impaired, evaluating whether an impairment is other-than-temporary and measuring impairment. EITF Issue No. 03-1 also provides disclosure guidance. The recognition and measurement guidance would have applied prospectively to all current and future investments within the scope of EITF Issue No. 03-1 in reporting periods beginning after June 15, 2004. However, in September 2004, the FASB issued FASB Staff Position (FSP) EITF 03-1-1 to delay the effective date of the recognition and measurement guidance. At its June 29, 2005 meeting, the FASB decided not to provide additional guidance on the meaning of other-than-temporary impairment, but directed its staff to issue proposed FSP EITF 03-1-a as final (retitled as FSP FAS 115-1 and FAS 124-1). The guidance in FSP FAS 115-1 and FAS 124-1 addresses the determination of when an investment is considered impaired, whether that impairment is other than temporary, and the measurement of an impairment loss. The FSP also includes accounting considerations subsequent to the recognition of an other-than-temporary impairment and requires certain disclosures about unrealized losses that have not been recognized as other-than-temporary impairments. The guidance in this FSP amends FASB Statement No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” and FASB Statement No. 124, “Accounting for Certain Investments Held by Not-for-Profit Organizations,” and adds a footnote to APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” The guidance in this FSP nullifies certain requirements of EITF Issue No. 03-1 and supersedes EITF Abstracts, Topic D-44, “Recognition of Other-Than-Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value.” The guidance in this FSP is required to be applied to reporting periods beginning after December 15, 2005. Because the impact of adopting the provisions of FSP FAS 115-1 will be dependent on future events and circumstances, management cannot predict such impact.

Medicare Prescription Drug, Improvement and Modernization Act of 2003. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the 2003 Act) was signed into law on December 8, 2003. The 2003 Act expanded Medicare to include for the first time coverage for prescription drugs. The 2003 Act provides that persons eligible for Medicare benefits can enroll in Part D, prescription drug coverage, for a monthly premium. Alternatively, if an employer sponsors a retiree health plan that provides benefits determined to be actuarially equivalent to those covered under the Medicare standard prescription drug benefit, the employer will be paid a subsidy of 28 percent of a participant’s drug costs between $250 and $5,000 if the participant waives coverage under Medicare Part D.

In May 2004, the FASB issued FSP No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” which was effective for the first interim or annual period beginning after June 15, 2004. When an employer is able to determine that benefits provided by its plan are actuarially equivalent to the Medicare Part D benefits, the FSP requires (a) treatment of the effects of the federal subsidy as an actuarial gain like similar gains and losses, and (b) certain financial statement disclosures related to the impact of the 2003 Act for employers that sponsor postretirement health care plans providing prescription drug benefits.

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The accumulated postretirement benefit obligation for the Company’s plans as of December 31, 2005 has been reduced by an estimated $3.3 million for the subsidy related to benefits attributed to past service. The net periodic postretirement benefit cost for 2006 has been reduced by an estimated $0.5 million for the subsidy.

Share-based payment. In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment,” which requires companies to recognize the grant-date fair value of stock options and other equity-based compensation issued to employees in the income statement. In March 2005, the SEC issued Staff Accounting Bulletin (SAB) No. 107, which provides accounting, disclosure, valuation and other guidance related to share-based payment arrangements. The Company adopted the provisions of SFAS No. 123 (revised 2004) and the guidance in SAB No. 107 on January 1, 2006 with no income statement effect.

Tax effects of income from domestic production activities. In December 2004, the FASB issued FSP No. 109-1, “Application of FASB Statement No. 109, Accounting for Income Taxes, for the Tax Deduction Provided to U.S. Based Manufacturers by the American Jobs Creation Act of 2004,” which was effective upon issuance. FSP No. 109-1 clarifies that the new deduction for qualified domestic production activities should be accounted for as a special deduction under SFAS No. 109, and not as a tax-rate reduction, because the deduction is contingent on performing activities identified in the new tax law.

Management is currently reviewing various aspects of the American Jobs Creation Act of 2004 (the 2004 Act), including proposed regulations relating to the 2004 Act recently issued by the Internal Revenue Service. There are at least two provisions with potential implications for the Company:

1. Manufacturing tax incentives for the production of electricity beginning in 2005. Taxpayers will be able to deduct a percentage (3% in 2005 and 2006, 6% in 2007 through 2009, and 9% in 2010 and thereafter) of the lesser of their qualified production activities income or their taxable income.

2. Generally for electricity sold and produced after October 22, 2004, the 2004 Act expands the income tax credit for electricity produced from certain sources to include open-loop biomass, geothermal and solar energy, small irrigation power, landfill gas, trash combustion and qualifying refined coal production facilities.

These provisions had no impact on HECO’s consolidated net income for 2005 and based on current estimates, management expects that the provisions will not have a significant impact on HECO’s consolidated net income in the future, pending further guidance from the Internal Revenue Service.

Asset retirement obligations. In March 2005, the FASB issued FIN 47, “Accounting for Conditional Asset Retirement Obligations,” which requires recognition of a liability for the fair value of a legal obligation to perform asset-retirement activities that are conditional on a future event if the amount can be reasonably estimated. The Company adopted the provisions of FIN 47 on December 31, 2005 and recorded an asset retirement obligation of $0.3 million for estimated remediation activities for certain transformers that contain polychlorinated biphenyl contaminated oil. The pro forma amounts of the asset retirement obligation, measured using information, assumptions, and interest rates as of December 31, 2005, would have been $0.3 million as of December 31, 2004 and 2003.

The Company owns assets for which the fair value of the asset retirement obligation cannot be reasonably determined because the asset-retirement activities associated with the legal obligation are contingent on future events which, at this time, cannot be reasonably determined. These assets include certain parts of a power plant and a fuel-oil pipeline which may be required to be dismantled upon retirement of another power plant. The Company currently intends to operate these assets for the foreseeable future and because of the indeterminate retirement dates, are unable to reasonably estimate the fair value of any legal obligations. The asset retirement obligation for these assets will be recorded once the future events can be reasonably determined.

Accounting changes and error corrections. In June 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections.” This new standard replaces APB Opinion No. 20, “Accounting Changes,” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements.” Among other changes, SFAS No. 154 requires that a voluntary change in accounting principle be applied retrospectively so that all prior

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period financial statements presented are based on the new accounting principle, unless it is impracticable to do so. SFAS No. 154 also provides that (1) a change in method of depreciating or amortizing a long-lived nonfinancial asset be accounted for as a change in estimate (prospectively) that was effected by a change in accounting principle, and (2) correction of errors in previously issued financial statements should be termed a “restatement.” SFAS No. 154 is effective for accounting changes and error corrections made in fiscal years beginning after December 15, 2005. Because the impact of adopting the provisions of SFAS No. 154 will be dependent on future events and circumstances, management cannot predict such impact.

Reclassifications

Certain reclassifications have been made to prior years’ financial statements to conform to the 2005 presentation. For example, assets and liabilities as of December 31, 2004 have been restated for the reclassification of regulatory assets from “Regulatory liabilities, net” to “Regulatory assets.”

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, 2005	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. Unconsolidated variable interest entities

Trust financing entities. HECO Capital Trust I (Trust I) was a financing entity, which issued, in 1997, $50 million of 8.05% Cumulative Quarterly Income Preferred Securities, Series 1997 (1997 Trust Preferred Securities) to the public. In March 2004, HECO, HELCO and MECO borrowed the proceeds of the sale of HECO Capital Trust III’s 2004 Trust Preferred Securities and, in April 2004, applied the proceeds, along with other corporate funds, to redeem the 1997 Trust Preferred Securities. HECO Capital Trust II (Trust II) was a financing entity, which issued, in 1998, $50 million of 7.30% Cumulative Quarterly Income Preferred Securities, Series 1998 (1998 Trust Preferred Securities) to the public. In April 2004, the electric utilities used funds primarily from short-term borrowings from HEI and from the issuance of commercial paper by HECO to redeem the 1998 Trust Preferred Securities. Trust I and Trust II, each a Delaware statutory trust, were consolidated subsidiaries of HECO through December 31, 2003. Since HECO, as the common security holder, did not absorb the majority of the variability of the trusts, HECO was not the primary beneficiary and, in accordance with FIN 46R, did not consolidate the trusts as of January 1, 2004. Trust I and Trust II were dissolved and terminated in 2004.

HECO Capital Trust III (Trust III) was created and exists for the exclusive purposes of (i) issuing in March 2004 2,000,000 6.50% Cumulative Quarterly Income Preferred Securities, Series 2004 (2004 Trust Preferred Securities) ($50 million aggregate liquidation preference) to the public and trust common securities

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($1.5 million aggregate liquidation preference) to HECO, (ii) investing the proceeds of these trust securities in 2004 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 trust securities and (iv) engaging in only those other activities necessary or incidental thereto. The 2004 Trust Preferred Securities are mandatorily redeemable at the maturity of the underlying debt on March 18, 2034, which maturity may be extended to no later than March 18, 2053; and are redeemable at the issuer’s option without premium beginning on March 18, 2009. The 2004 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 III. Trust III has at all times been an unconsolidated subsidiary of HECO. Since HECO, as the common security holder, does not absorb the majority of the variability of Trust III, HECO is not the primary beneficiary and does not consolidate Trust III in accordance with FIN 46R. Trust III’s balance sheet as of December 31, 2005 consisted of $51.5 million of 2004 Debentures; $50.0 million of 2004 Trust Preferred Securities; and $1.5 million of trust common securities. Trust III’s income statement for 2005 consisted of $3.4 million of interest income received from the 2004 Debentures; $3.3 million of distributions to holders of the Trust Preferred Securities; and $0.1 million of common dividends on the trust common securities to HECO. So long as the 2004 Trust Preferred Securities are outstanding, HECO is not entitled to receive any funds from Trust III other than pro rata distributions, subject to certain subordination provisions, on the trust common securities. In the event of a default by HECO in the performance of its obligations under the 2004 Debentures or under its Guarantees, or in the event HECO, HELCO or MECO elect to defer payment of interest on any of their respective 2004 Debentures, then HECO will be subject to a number of restrictions, including a prohibition on the payment of dividends on its common stock.

Kalaeloa Partners, L.P. In October 1988, HECO entered into a PPA with Kalaeloa, which provided that HECO would purchase 180 MW of firm capacity for a period of 25 years beginning in May 1991. In October 2004, HECO and Kalaeloa entered into amendments, which together effectively increased the firm capacity from 180 MW to 208 MW. The PPA and amendments have been approved by the PUC. The energy payments that HECO makes to Kalaeloa include: 1) a fuel component, with a fuel price adjustment based on the cost of low sulfur fuel oil, 2) a fuel additives cost component, and 3) a non-fuel component, with an adjustment based on changes in the Gross National Product Implicit Price Deflator. The capacity payments that HECO makes to Kalaeloa are fixed in accordance with the PPA.

Kalaeloa is a Delaware limited partnership formed on October 13, 1988 for the purpose of designing, constructing, owning and operating a 200 MW cogeneration facility on Oahu, which includes two 75 MW oil-fired combustion turbines, two waste heat recovery steam generators, a 50 MW turbine generator and other electrical, mechanical and control equipment. The two combustion turbines were upgraded during 2004 resulting in an increase in the facility’s nominal output rating to approximately 220 MW. Kalaeloa has a PPA with HECO (described above) and a steam delivery contract with another customer, the term of which coincides with the PPA. The facility has been certified by the Federal Energy Regulatory Commission as a Qualified Facility under the Public Utilities Regulatory Policies Act of 1978.

Pursuant to the provisions of FIN 46R, HECO is deemed to have a variable interest in Kalaeloa via HECO’s PPA with Kalaeloa. However, management has concluded that HECO is not the primary beneficiary of Kalaeloa because HECO does not absorb the majority of Kalaeloa’s expected losses nor receive a majority of Kalaeloa’s expected residual returns and, thus, HECO has not consolidated Kalaeloa in its consolidated financial statements. A significant factor which affected the level of expected losses HECO would absorb is the fact that HECO’s exposure to fuel price variability is limited to the remaining term of the PPA as compared to the facility’s remaining useful life. Although HECO absorbs fuel price variability for the remaining term of the PPA, the PPA does not expose HECO to losses as the fuel and fuel related energy payments under the PPA have been approved by the PUC for recovery from customers through base electric rates and through HECO’s energy cost adjustment clause to the extent the fuel and fuel related energy payments are not included in base energy rates.

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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 January 2003, MECO’s proportionate share of the 6.55% Series 1992 Special Purpose Revenue Bonds (SPRB), 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 SPRB were refunded with the proceeds from the 4.75% Refunding Series 2003A SPRB loaned to HELCO ($14 million). In addition, HECO’s and HELCO’s proportionate share of the 6.55% Series 1992 SPRB were refunded with the proceeds from the 5.00% Refunding Series 2003B SPRB that were loaned to HECO ($40 million) and HELCO ($12 million). The redemption premium on refunding the Series 1992 SPRB 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.

In January 2005, the Department of Budget and Finance of the State of Hawaii issued, at par, Refunding Series 2005A SPRB in the aggregate principal amount of $47 million with a maturity of January 1, 2025 and a fixed coupon interest rate of 4.80% and loaned the proceeds from the sale to HECO, HELCO and MECO. The proceeds of such bonds, along with additional funds, were applied to redeem at a 1% premium a like principal amount of SPRB bearing a higher interest coupon (HECO’s, HELCO’s, and MECO’s aggregate $47 million of 6.60% Series 1995A SPRB with original maturity of January 1, 2025) in February 2005.

At December 31, 2005, the aggregate payments of principal required on long-term debt during the next five years are nil in each year.

5. Short-term borrowings

Short-term borrowings from nonaffiliates at December 31, 2005 and 2004 had a weighted average interest rate of 4.5% and 2.5%, respectively, and consisted entirely of commercial paper.

At December 31, 2005 and 2004, the Company maintained bank lines of credit which totaled $180 million ($90 million maturing in April 2006, $60 million maturing in May 2006 and $30 million maturing in August 2006) and $110 million, respectively. HECO maintains these lines of credit (at a base rate (Prime, Fed Funds, Bank Base, Bank Quoted or LIBOR rate) plus a margin ranging from 0 to 81 basis points) to support the issuance of commercial paper and for other general corporate purposes. Fees to maintain the lines of credit are not material. HECO’s lines of credit have covenants, including covenants related to capitalization ratios. None of the lines are secured. There were no borrowings under any line of credit during 2005 and 2004.

6. Regulatory assets and liabilities

In accordance with SFAS No. 71, the Company’s financial statements reflect assets, liabilities, revenues and expenses based on current cost-based rate-making regulations. 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 its operations currently satisfy the SFAS No. 71 criteria. If events or circumstances should change so that those criteria are no longer satisfied, the Company expects that the regulatory assets would be charged to income and the regulatory liabilities would be credited to income or refunded to ratepayers. 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 for regulatory liabilities or if regulatory liabilities are required to be refunded to ratepayers.

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Regulatory liabilities represent amounts included in rates and collected from ratepayers for costs expected to be incurred in the future. For example, the regulatory liability for cost of removal in excess of salvage value represents amounts that have been collected from ratepayers for costs that are expected to be incurred in the future to retire utility plant. Regulatory assets represent deferred costs expected to be fully recovered through rates over PUC authorized periods. Generally, the Company does not earn a return on their regulatory assets, however, they have been allowed to accrue and recover interest on its regulatory assets for integrated resource planning costs. Noted in parenthesis are the original PUC authorized amortization or recovery periods and the remaining amortization or recovery periods as of December 31, 2005, if different.

Regulatory assets were as follows:

December 31	2005		2004
(in thousands)
Income taxes, net (1 to 36 years)	$	70,743	$	68,780
Postretirement benefits other than pensions (18 years; 7 years)		12,528		14,318
Unamortized expense and premiums on retired debt and equity issuances (11 to 30 years; 1 to 23 years)		16,081		15,509
Integrated resource planning costs, net (1 year)		2,395		1,554
Vacation earned, but not yet taken (1 year)		5,669		5,011
Other (1 to 20 years)		3,302		3,458
	$	110,718	$	108,630

Regulatory liabilities were as follows:

December 31	2005		2004
(in thousands)
Cost of removal in excess of salvage value (1 to 60 years)	$	217,493	$	197,089
Other (5 years; 2 to 5 years)		1,711		—
	$	219,204	$	197,089

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7. Income taxes

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

December 31	2005			2004			2003
(in thousands)
Federal:
Current	$	23,799		$	25,763		$	32,167
Deferred		17,497			21,973			13,171
Deferred tax credits, net		(1,351	)		(1,446	)		(1,504	)
		39,945			46,290			43,834
State:
Current		(1,407	)		(1,777	)		4,828
Deferred		3,020			334			928
Deferred tax credits, net		3,471			5,212			585
		5,084			3,769			6,341
Total	$	45,029		$	50,059		$	50,175

Income tax benefits related to nonoperating activities, included in “Other, net” on the consolidated statements of income, amounted to $0.4 million, $0.6 million and $0.4 million for 2005, 2004 and 2003, 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	2005			2004		2003
(in thousands)
Amount at the federal statutory income tax rate	$	41,989		$	46,978	$	46,235
State income taxes on operating income, net of effect on federal income taxes		3,305			2,450		4,121
Other		(265	)		631		(181	)
Income taxes charged to operating expenses	$	45,029		$	50,059	$	50,175

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

December 31	2005		2004
(in thousands)
Deferred tax assets:
Cost of removal in excess of salvage value	$	85,292	$	76,687
Contributions in aid of construction and customer advances		38,406		39,159
Other		12,821		12,751
		136,519		128,597
Deferred tax liabilities:
Property, plant and equipment		272,467		249,799
Regulatory assets, excluding amounts attributable to property, plant and equipment		27,588		26,756
Pension		40,442		38,153
Other		4,396		3,082
		344,893		317,790
Net deferred income tax liability	$	208,374	$	189,193

The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Based upon historical taxable income, projections for future taxable income and available tax planning strategies, management believes it is more likely than not the Company will realize substantially all of the benefits of the deferred tax assets.

As of December 31, 2005, $0.2 million, net of tax effects, was accrued for unresolved tax issues and related interest. Although not probable, adverse developments on unresolved issues could result in additional charges to net income in the future. Based on information currently available, the Company believes it has adequately provided for unresolved income tax issues with federal and state tax authorities and related interest, and that the ultimate resolution of tax issues for all open tax periods will not have a material adverse effect on its results of operations, financial condition or liquidity.

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	2005		2004		2003
(in thousands)
Interest	$	46,221	$	46,041	$	41,601
Income taxes	$	20,554	$	26,914	$	36,316

Supplemental disclosures of noncash activities

The allowance for equity funds used during construction, which was charged primarily to construction in progress, amounted to $5.1 million, $5.8 million and $4.3 million in 2005, 2004 and 2003, respectively.

The estimated fair value of noncash contributions in aid of construction amounted to $11.8 million, $4.9 million and $13.9 million in 2005, 2004 and 2003, respectively.

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9. Major customers

HECO and its subsidiaries received approximately 10% ($176 million), 10% ($148 million) and 10% ($135 million) of their operating revenues from the sale of electricity to various federal government agencies in 2005, 2004 and 2003, 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). 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 terminates its participation in the Plan, the interest of each affected participant would become 100% vested to the extent funded. Upon the termination of the Plan, assets would be distributed to affected participants in accordance with the applicable allocation provisions of ERISA and any excess assets that exist would be paid to the participating employers. Participants’ benefits in the Plan 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 (HECO Benefits Plan). Health benefits are also provided to dependents of eligible employees. The contribution for health benefits paid by the participating employers is based on the 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 Plan.

Among other provisions, the HECO Benefits 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. See “Medicare Prescription Drug, Improvement and Modernization Act of 2003” under “Recent accounting pronouncements and interpretations” in Note 1.

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

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Pension and other postretirement benefit plans information

The changes in the obligations and assets of the Company’s retirement benefit plans, the funded status of these plans and the unrecognized and recognized amounts related to these plans and reflected in the Company’s balance sheet were as follows:

	Pension benefits						Other benefits
(in thousands)	2005			2004			2005			2004
Benefit obligation, January 1	$	802,059		$	749,025		$	195,176		$	176,001
Service cost		23,832			21,446			5,098			4,407
Interest cost		46,817			45,776			10,818			10,503
Amendments		—			—			—			(1,212	)
Actuarial loss (gain)		26,760			24,348			(16,778	)		13,504
Benefits paid and expenses		(40,388	)		(38,536	)		(8,475	)		(8,027	)
Benefit obligation, December 31		859,080			802,059			185,839			195,176
Fair value of plan assets, January 1		712,257			661,681			107,547			96,498
Actual return on plan assets		50,605			64,337			7,726			9,849
Employer contribution		7,627			24,775			10,554			9,227
Benefits paid and expenses		(40,388	)		(38,536	)		(8,475	)		(8,027	)
Fair value of plan assets, December 31		730,101			712,257			117,352			107,547
Funded status		(128,979	)		(89,802	)		(68,487	)		(87,629	)
Unrecognized net actuarial loss		238,002			199,504			24,116			39,311
Unrecognized net transition obligation		4			6			21,907			25,037
Unrecognized prior service gain		(5,767	)		(6,537	)		—			—
Net amount recognized, December 31	$	103,260		$	103,171		$	(22,464	)	$	(23,281	)
Amounts recognized in the balance sheet consist of:
Prepaid benefit cost	$	106,490		$	106,198		$	—		$	—
Accrued benefit liability		(3,230	)		(3,027	)		(22,464	)		(23,281	)
Net amount recognized, December 31	$	103,260		$	103,171		$	(22,464	)	$	(23,281	)

The dates used to determine retirement benefit measurements for the defined benefit plans were December 31 of 2005, 2004 and 2003. The defined benefit pension plans’ accumulated benefit obligations, which do not consider projected pay increases, as of December 31, 2005 and 2004 were $728 million and $680 million, respectively. Depending on the performance of the pension plan assets, the status of interest rates and numerous other factors, including changes in accounting standards, 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 (AOCI), but would result in the removal of the prepaid pension asset ($106 million as of December 31, 2005) from the Company’s balance sheet.

In December 2005, the Company submitted a request to the PUC for approval to record, as a regulatory asset pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” and include in rate base the amount that would otherwise be charged to AOCI as required under the provisions of SFAS No. 87 in the event the Company were required to record a minimum pension liability on the measurement date, and to allow the Company to continue to maintain, in subsequent years, a regulatory asset in rate base, for any pension liability that would otherwise be charged to AOCI. Under such an accounting treatment, if in later years the fair values of the Company’s pension assets were to exceed the accumulated benefit obligations, the Company would reverse the regulatory assets and associated remaining minimum liabilities. Although this relief was not necessary for 2005 because the fair value of the Company’s pension assets on December 31,

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2005 exceeded the accumulated benefit obligation, such relief may be necessary in future years. Management cannot predict whether the PUC will approve this request, or when a decision will be made.

The Company has determined the market-related value of retirement benefit plan assets by calculating the difference between the expected return and the actual return on the fair value of the plan assets, then amortizing the difference over future years – 0% in the first year and 25% in years two to five, and finally adding or subtracting the unamortized differences for the past four years from fair value. The method includes a 15% range around the fair value of such assets (i.e., 85% to 115% of fair value). If the market-related value is outside the 15% range, then the amount outside the range will be recognized immediately in the calculation of annual net periodic benefit cost.

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 retirement 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’ investment consultants, which projected the return over the long term to be in excess of 9%, based on the target asset allocation.

The weighted-average asset allocation of retirement defined benefit plans was as follows:

	Pension benefits								Other benefits
					Investment policy 2								Investment policy 2
December 31	2005		2004		Target		Range		2005		2004		Target		Range
Asset category
Equity securities	69	%	73	%	70	%	65-75	%	68	%	73	%	70	%	65-75	%
Debt securities	29		25		30		25-35	%	31		26		30		25-35	%
Other 1	2		2		—		—		1		1		—		—
	100	%	100	%	100	%			100	%	100	%	100	%

¹ Other includes alternative investments, which are relatively illiquid in nature and will remain as plan assets until an appropriate liquidation opportunity occurs.

² As of December 31.

HECO and its subsidiaries’ current estimate of contributions to the retirement benefit plans in 2006 is $11 million.

As of December 31, 2005, the benefits expected to be paid under the retirement benefit plans in 2006, 2007, 2008, 2009, 2010 and 2011 through 2015 amounted to $52 million, $53 million, $55 million, $57 million, $59 million and $333 million, respectively.

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

	Pension benefits						Other benefits
December 31	2005		2004		2003		2005		2004		2003
Benefit obligation
Discount rate	5.75	%	6.00	%	6.25	%	5.75	%	6.00	%	6.25	%
Expected return on plan assets	9.0		9.0		9.0		9.0		9.0		9.0
Rate of compensation increase	4.6		4.6		4.6		4.6		4.6		4.6
Net periodic benefit cost (years ended)
Discount rate	6.00		6.25		6.75		6.00		6.25		6.75
Expected return on plan assets	9.0		9.0		9.0		9.0		9.0		9.0
Rate of compensation increase	4.6		4.6		4.6		4.6		4.6		4.6

As of December 31, 2005, the assumed health care trend rates for 2006 and future years were as follows: medical, 10.00%, grading down to 5.00% for 2011 and thereafter; dental, 5.00%; and vision, 4.00%. At

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December 31, 2004, the assumed health care trend rates for 2005 and future years were as follows: medical, 10.00%, grading down to 5.00% for 2010 and thereafter; dental, 5.00%; and vision, 4.00%.

The components of net periodic benefit cost were as follows:

	Pension benefits									Other benefits
Years ended December 31	2005			2004			2003			2005			2004			2003
(in thousands)
Service cost	$	23,832		$	21,446		$	18,899		$	5,098		$	4,407		$	3,475
Interest cost		46,817			45,776			43,553			10,818			10,503			10,161
Expected return on plan assets		(67,078	)		(66,681	)		(55,678	)		(9,704	)		(9,553	)		(7,521	)
Amortization of unrecognized transition obligation		2			2			952			3,130			3,129			3,264
Amortization of prior service gain		(770	)		(744	)		(750	)		—			—			—
Recognized actuarial loss		4,735			217			2,873			395			—			—
Net periodic benefit cost	$	7,538		$	16		$	9,849		$	9,737		$	8,486		$	9,379

Of the net periodic pension benefit costs, the Company recorded expense of $6 million in 2005, $0.1 million in 2004 and $7 million in 2003, and charged the remaining amounts primarily to electric utility plant. Of the net periodic other than pension benefit costs, the Company expensed $7 million, $6 million and $7 million in 2005, 2004 and 2003, 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, 2005, and $3 million, $3 million and nil, respectively, as of December 31, 2004.

The health care cost trend rate assumptions can have a significant effect on the amounts reported for other benefits. At December 31, 2005, a one-percentage-point increase in the assumed health care cost trend rates would have increased the total service and interest cost by $0.5 million and the postretirement benefit obligation by $4.2 million, and a one-percentage-point decrease would have reduced the total service and interest cost by $0.5 million and the postretirement benefit obligation by $4.5 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, 2014 (at prices tied to the market prices of petroleum products in Singapore and Los Angeles). Based on the average price per barrel as of January 1, 2006, the estimated cost of minimum purchases under the fuel supply contracts is $542 million each year for 2006 and 2007, $543 million for 2008, $542 million each year for 2009 and 2010 and a total of $2.2 billion for the period 2011 through 2014. The actual cost of purchases in 2006 could vary substantially from this estimate as a result of changes in market prices, quantities actually purchased and/or other factors. HECO and its subsidiaries purchased $662 million, $490 million and $390 million of fuel under contractual agreements in 2005, 2004 and 2003, respectively.

Power purchase agreements (PPAs). As of December 31, 2005, HECO, HELCO and MECO had six firm capacity PPAs for a total of 540 MW of firm capacity. Of the 540 MW of firm capacity under PPAs, approximately 91% is under PPAs with AES Hawaii, Inc. (PPA executed in March 1988), Kalaeloa Partners, L.P. (October 1988), Hamakua Energy Partners, L.P. (October 1997) and HPower (March 1986). The primary business activities of these six IPPs are the generation and sale of power to the Company (and municipal waste disposal in the case of HPower). Purchases from these six IPPs and all other IPPs totaled $458 million, $399 million and $368 million for 2005, 2004 and 2003, respectively. The PUC allows rate recovery for energy

26

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 $118 million in 2006, $121 million in 2007, $119 million in 2008, $116 million in 2009, $119 million in 2010 and a total of $1.3 billion in the period from 2011 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, HELCO and MECO pass on changes in the fuel component of the energy charges to customers through the energy cost adjustment clause in their rate schedules. HECO, HELCO and MECO do not operate, or participate in the operation of, any of the facilities that provide power under the agreements. Title to the facilities does not pass to HECO, HELCO or MECO upon expiration of the agreements, and the agreements do not contain bargain purchase options for the facilities.

Interim increases. As of December 31, 2005, the Company had recognized $32 million of revenues with respect to interim orders regarding certain integrated resource planning costs and an Oahu general rate increase, which revenues are subject to refund, with interest, if and to the extent they exceed the amounts allowed in final orders.

HELCO power situation.

Historical context. In 1991, HELCO began planning to meet increased electric generation demand forecast for 1994. It planned to install at its Keahole power plant two 20 megawatt (MW) combustion turbines (CT-4 and CT-5), followed by an 18 MW heat recovery steam 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. In 1995, the PUC allowed HELCO to pursue construction of and commit expenditures for CT-5 and ST-7, but noted that such costs are not to be included in rate base until the project is installed and “is used and useful for utility purposes.”

Status. Installation of CT-4 and CT-5 was significantly delayed as a result of land use and environmental permitting delays and related administrative proceedings and lawsuits. However, in 2003, the parties opposing the plant expansion project (other than Waimana Enterprises, Inc. (Waimana), which did not participate in the settlement discussions and opposes the settlement) entered into a settlement agreement with HELCO and several Hawaii regulatory agencies, intended in part to permit HELCO to complete CT-4 and CT-5 (Settlement Agreement). Subsequently, CT-4 and CT-5 were installed and put into limited commercial operation in May and June 2004, respectively. The BLNR’s construction deadline of July 31, 2005 has been met. Noise mitigation equipment has been installed on CT-4 and CT-5 and the need for additional noise mitigation work for CT-5 (not requiring any further construction) is being examined to ensure compliance with the night-time noise standard applicable to the plant. Currently, HELCO can operate the generating units at Keahole as required to meet its system needs.

Currently, four appeals to the Hawaii Supreme Court by Waimana have been briefed and are awaiting decision. These are appeals to judgments of the Third Circuit Court involving (i) vacating of a November 2002 Final Judgment which had halted construction; (ii) the Board of Land and Natural Resources (BLNR) 2003 construction period extension; (iii) the BLNR’s approval of a revocable permit allowing HELCO to use brackish well water as the primary source of water for operating the Keahole plant; and (iv) appeals (now consolidated) by Waimana and another party of judgments upholding the BLNR’s approval of the long-term lease allowing HELCO to use brackish well water. In the third appeal, additional briefs were filed on July 15, 2005 on the question of whether the appeal is moot given the granting by the BLNR of a long-term water lease allowing HELCO to use brackish water. Full implementation of the Settlement Agreement is conditioned on obtaining final dispositions of all litigation pending at the time of the Settlement Agreement. If the remaining dispositions

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are obtained, as HELCO believes they will be, then HELCO must undertake a number of actions under the Settlement Agreement, including expediting efforts to obtain the permits and approvals necessary for installation of ST-7 with selective catalytic reduction emissions control equipment, assisting the Department of Hawaiian Home Lands in installing solar water heating in its housing projects, supporting the Keahole Defense Coalition’s participation in certain PUC cases, and cooperating with neighbors and community groups (including a Hot Line service). Some of these actions have already commenced.

In November 2003, HELCO filed a boundary amendment petition (to reclassify the Keahole plant site from conservation land use to urban land use) with the State Land Use Commission, which was approved in October 2005. HELCO’s plans for ST-7 are progressing, but construction cannot start until HELCO obtains County rezoning to a “General Industrial” classification and obtains the necessary permits. The application for rezoning was filed with the County in November 2005. In January 2006, the County Planning Commission recommended approval of the rezoning to the County Council. Further action by the County Council is pending.

Costs incurred; management’s evaluation. As of December 31, 2005, HELCO’s capitalized costs incurred in its efforts to put CT-4 and CT-5 into service and to support existing units (excluding costs for pre-air permit facilities) amounted to approximately $110 million, including $43 million for equipment and material purchases, $47 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 accruing AFUDC. The $110 million of costs was reclassified from construction in progress to plant and equipment in 2004 and 2005 and depreciated beginning January 1 of the year following the reclassification.

Management believes that the prospects are good that the remaining Settlement Agreement conditions will be satisfied and that any further necessary permits will be obtained and that the appeals will be favorably resolved. However, HELCO’s electric rates will not change specifically as a result of including CT-4 and CT-5 in plant and equipment until HELCO files a rate increase application and the PUC grants HELCO rate relief. In December 2005, HELCO notified the PUC that it intends to file a request for an electric rate increase in spring 2006 in part to recover CT-4 and CT-5 costs. While management believes that no adjustment to costs incurred to put CT-4 and CT-5 into service is required as of December 31, 2005, 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 these costs.

East Oahu Transmission Project (EOTP). HECO transmits bulk power to the Honolulu/East Oahu area over two major transmission corridors (Northern and Southern). HECO had planned to construct a partial underground/partial overhead 138 kilovolt (kV) line from the Kamoku substation to the Pukele substation, which serves approximately 16% of Oahu’s electrical load, including Waikiki, in order to close the gap between the Southern and Northern corridors and provide a third transmission line to the Pukele substation, but an application for a permit which would have allowed construction in the originally planned route through conservation district lands was denied in June 2002.

HECO continues to believe that the proposed reliability project (the East Oahu Transmission Project) is needed. In December 2003, HECO filed an application with the PUC requesting approval to commit funds (currently estimated at $57 million; see costs incurred below) for a revised EOTP using a 46 kV system. In March 2004, the PUC granted intervenor status to an environmental organization and three elected officials (collectively treated as one party), and a more limited participant status to four community organizations. The environmental review process has been completed and the PUC issued a Finding of No Significant Impact in April 2005. Subject to PUC approval, HECO plans to construct the revised project, none of which is in conservation district lands, in two phases, currently projected for completion in 2007 and 2009.

As of December 31, 2005, the accumulated costs recorded for the EOTP amounted to $26 million, including $12 million of planning and permitting costs incurred prior to 2003, when HECO was denied the approval necessary for the partial underground/partial overhead 138 kV line, $3 million of planning and permitting costs incurred after 2002, and $11 million for AFUDC. In the written testimony filed in June 2005, the Consumer Advocate’s consultant contended that HECO should always have planned for a project using only the 46 kV system and recommended that HECO be required to expense the $12 million incurred before

28

2003, and the related AFUDC of $5 million. In rebuttal testimony filed in August 2005, HECO contested the consultant’s recommendation, emphasizing that the originally proposed 138 kV line would have been a more comprehensive and robust solution to the transmission concerns the project addressed. The PUC held an evidentiary hearing on HECO’s application in November 2005. Just prior to the evidentiary hearing, the PUC approved that part of a stipulation between HECO and the Consumer Advocate that this proceeding should determine whether HECO should be given approval to expend funds for the EOTP provided that no part of the EOTP costs may be recovered from ratepayers unless and until the PUC grants HECO recovery in a rate case (which is consistent with other projects), and that the issue as to whether the pre-2003 planning and permitting costs, and related AFUDC, should be included in the project costs is reserved to, and may be raised in, the next HECO rate case (or other proceeding). Management believes no adjustment to project costs is required as of December 31, 2005. 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 First Circuit Court of Hawaii alleging that the State of Hawaii and HECO’s other customers had been overcharged for electricity by over $1 billion since September 1992 due to alleged excessive prices in the PUC-approved amended PPA between HECO and AES Hawaii. The PUC proceedings in which the amended PPA was approved addressed a number of issues, including whether the terms and conditions of the PPA were reasonable.

As a result of rulings by the First Circuit Court in 2003, all claims for relief and causes of action in the amended complaint were dismissed. In October 2003, plaintiff Beverly 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. On July 16, 2004, the Supreme Court retained jurisdiction of the appeal (rather than assign the appeal to the Intermediate Court of Appeals) and a decision is pending. In the opinion of management, the ultimate disposition of this matter will not have a material adverse effect on HECO’s consolidated financial position, results of operations or liquidity.

Environmental regulation. HECO and its subsidiaries are subject to environmental laws and regulations that regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic substances.

HECO, HELCO and MECO, like other utilities, periodically identify petroleum or other chemical releases into the environment associated with current operations and report and take action on these releases when and as required by applicable law and regulations. Except as otherwise disclosed herein, the Company believes the costs of responding to its releases identified to date will not have a material adverse effect, individually and in the aggregate, on the Company’s consolidated financial statements.

Additionally, current environmental laws may require HECO and its subsidiaries to investigate whether releases from historical operations may have contributed to environmental impacts, and, where appropriate, respond to such releases, even if they were not inconsistent with law or standard industrial practices prevailing at the time when they occurred. Such releases may involve area-wide impacts contributed to by multiple potentially responsible parties.

Honolulu Harbor investigation. In 1995, the Department of Health of the State of Hawaii (DOH) issued letters indicating that it had identified a number of parties, including HECO, who appeared to be potentially responsible for historical subsurface petroleum contamination and/or operated their facilities upon petroleum-contaminated land at or near Honolulu Harbor in the Iwilei district of Honolulu. Certain of the identified parties formed a work group to determine the nature and extent of any contamination and appropriate response actions, as well as identify additional potentially responsible parties (PRPs). The U.S. Environmental Protection Agency (EPA) became involved in the investigation in June 2000. Later in 2000, the DOH issued notices to additional PRPs. The parties in the work group and some of the new PRPs (collectively, the

29

Participating Parties) entered into a joint defense agreement and signed a voluntary response agreement with the DOH. The Participating Parties agreed to fund investigative and remediation work using an interim cost allocation method (subject to a final allocation) and have organized a limited liability company to perform the work.

Since 2001, subsurface investigation and assessment have 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 and DOH. Currently, the Participating Parties are preparing Remediation Alternatives Analyses, which will identify and recommend remedial approaches. HECO routinely maintains its facilities and has investigated its operations in the Iwilei area and ascertained that they are not releasing petroleum.

In 2001, management developed a preliminary estimate of HECO’s share of costs for continuing investigative work, remedial activities and monitoring at the Iwilei Unit of approximately $1.1 million (which was expensed in 2001 and of which $0.6 million has been incurred through February 28, 2006). 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 among the PRPs 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.

Regional Haze Rule amendments. In June 2005, the EPA finalized amendments to the July 1999 Regional Haze Rule that require emission controls known as best available retrofit technology (BART) for industrial facilities emitting air pollutants that reduce visibility in National Parks by causing or contributing to regional haze. States must develop BART implementation plans and schedules in accordance with the amended regional haze rule by December 2007. After Hawaii adopts its plan, HECO, MECO and HELCO will evaluate the impacts, if any, on them. If any of the utilities’ units are ultimately required to install post-combustion control technologies to meet BART emission limits, the capital and operations and maintenance costs could be significant.

Clean Water Act. Section 316(b) of the federal Clean Water Act requires that the EPA ensure that existing power plant cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts. Effective September 9, 2004, the EPA issued a new rule, which establishes location and technology-based design, construction and capacity standards for existing cooling water intake structures. These standards will apply to HECO’s Kahe, Waiau and Honolulu generating stations unless the utility can demonstrate that at each facility implementation of these standards will result in very high costs or little environmental benefit. HECO has until March 2008 to make this showing or demonstrate compliance. HECO has retained a consultant to develop a cost effective compliance strategy and a preliminary assessment of technologies and operational measures. HECO is developing a monitoring program and plans to perform a cost-benefit analysis to demonstrate that HECO’s existing intake systems have minimal environmental impacts, which demonstration would exempt HECO from the standards. Concurrently, HECO will evaluate alternative compliance mechanisms allowed by the rule, some of which could entail significant capital expenditures to implement.

Collective bargaining agreements. Approximately 58% of the Company’s employees are members of the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260, Unit 8, which is the only union representing employees of the Company. The current 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, May 1, 2005, November 1, 2005 and May 1, 2006; and 3% on November 1, 2006).

Limited insurance. The Company purchases insurance coverages to protect itself against loss of or damage to its properties and against claims made by third-parties and employees. However, the protection provided by such insurance is limited in significant respects and, in some instances, there is no coverage. HECO, HELCO and MECO’s overhead and underground transmission and distribution systems (with the exception of

30

substation buildings and contents) have a replacement value roughly estimated at $3 billion and are uninsured. Similarly, HECO, HELCO and MECO have no business interruption insurance. If a hurricane or other uninsured catastrophic natural disaster should occur, and if the PUC were not to allow the utilities to recover from ratepayers restoration costs and revenues lost from business interruption, their results of operations and financial condition could be materially adversely impacted. Also, certain insurance has substantial “deductibles”, limits on the maximum amounts that may be recovered and exclusions or limitations of coverage for claims related to certain perils. If a series of losses occurred, such as from a series of lawsuits in the ordinary course of business, each of which were subject to the deductible amount, or if the maximum limit of the available insurance were substantially exceeded, HECO, HELCO and MECO could incur losses in amounts that would have a material adverse effect on its results of operations and financial condition.

12. Regulatory restrictions on distributions to parent

As of December 31, 2005, net assets (assets less liabilities and preferred stock) of approximately $431 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 $3.3 million, $3.2 million and $2.9 million for general management and administrative services in 2005, 2004 and 2003, respectively. The amounts charged by HEI to its subsidiaries are allocated primarily on the basis of actual labor hours expended in providing such services.

HECO’s borrowings from HEI fluctuate during the year, and totaled nil and $12.0 million at December 31, 2005 and 2004, respectively. The interest charged on short-term borrowings from HEI is based on the rate HEI pays on its commercial paper borrowings, 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, or if HEI has no commercial paper borrowings, interest is based on HECO’s short-term external borrowing rate, or quoted rates from the Wall Street Journal for 30-day dealer-placed commercial paper.

Interest charged by HEI to HECO totaled $0.4 million, $0.5 million and $0.1 million in 2005, 2004 and 2003, respectively.

14. Significant group concentrations of credit risk

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

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15. Fair value of financial instruments

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

Cash and equivalents and short-term borrowings

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

Long-term debt

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

Off-balance sheet financial instruments

The fair values of off-balance sheet financial instruments were estimated based on quoted market prices of comparable instruments.

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

December 31	2005				2004
	Carrying Amount		Estimated fair value		Carrying amount		Estimated fair value
(in thousands)
Financial assets:
Cash and equivalents	$	143	$	143	$	327	$	327
Financial liabilities:
Short-term borrowings from nonaffiliates and affiliate		136,165		136,165		88,568		88,568
Long-term debt, net, including amounts due within one year		765,993		796,119		752,735		789,693
Off-balance sheet item
HECO-obligated preferred securities of trust subsidiary		50,000		51,400		50,000		52,400

Limitations

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

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16. Consolidating financial information (unaudited)

Consolidating balance sheet

	December 31, 2005
(in thousands)	HECO			HELCO		MECO		RHI	Reclassi- fications and Elimina- tions		HECO Consolidated
Assets
Utility plant, at cost
Land	$	25,699		3,018		4,317		—	—		$	33,034
Plant and equipment		2,304,142		766,714		678,530		—	—			3,749,386
Less accumulated depreciation		(898,351	)	(275,444	)	(282,742	)	—	—			(1,456,537	)
Plant acquisition adjustment, net		—		—		145		—	—			145
Construction in progress		108,060		11,414		28,282		—	—			147,756
Net utility plant		1,539,550		505,702		428,532		—	—			2,473,784
Investment in wholly owned subsidiaries, at equity		383,715		—		—		—	(383,715	)[2]		—
Current assets
Cash and equivalents		8		3		4		128	—			143
Advances to affiliates		49,700		—		5,250		—	(54,950	)[1]		—
Customer accounts receivable, net		81,870		21,652		20,373		—	—			123,895
Accrued unbilled revenues, net		62,701		14,675		13,945		—	—			91,321
Other accounts receivable, net		10,212		2,772		1,185		—	592	[1]		14,761
Fuel oil stock, at average cost		64,309		7,868		13,273		—	—			85,450
Materials & supplies, at average cost		14,128		3,204		9,642		—	—			26,974
Prepayments and other		89,982		15,929		8,991		—	—			114,902
Total current assets		372,910		66,103		72,663		128	(54,358	)		457,446
Other long-term assets
Regulatory assets		81,682		14,596		14,440		—	—			110,718
Unamortized debt expense		9,778		2,362		2,221		—	—			14,361
Other		17,816		3,696		3,640		—	—			25,152
Total other long-term assets		109,276		20,654		20,301		—	—			150,231
	$	2,405,451		592,459		521,496		128	(438,073	)	$	3,081,461
Capitalization and liabilities
Capitalization
Common stock equity	$	1,039,259		189,407		194,190		118	(383,715	)[2]	$	1,039,259
Cumulative preferred stock–not subject to mandatory redemption		22,293		7,000		5,000		—	—			34,293
Long-term debt, net		481,132		131,009		153,852		—	—			765,993
Total capitalization		1,542,684		327,416		353,042		118	(383,715	)		1,839,545
Current liabilities
Short-term borrowings-nonaffiliates		136,165		—		—		—	—			136,165
Short-term borrowings-affiliate		5,250		49,700		—		—	(54,950	)[1]		—
Accounts payable		86,843		19,503		15,855		—	—			122,201
Interest and preferred dividends payable		7,217		1,311		1,664		—	(202	)[1]		9,990
Taxes accrued		84,054		24,252		25,277		—	—			133,583
Other		24,971		3,566		7,791		10	794	[1]		37,132
Total current liabilities		344,500		98,332		50,587		10	(54,358	)		439,071
Deferred credits and other liabilities
Deferred income taxes		160,351		25,147		22,876		—	—			208,374
Regulatory liabilities		148,898		40,535		29,771		—	—			219,204
Unamortized tax credits		31,209		12,693		11,425		—	—			55,327
Other		21,522		31,781		10,374		—	—			63,677
Total deferred credits and other liabilities		361,980		110,156		74,446		—	—			546,582
Contributions in aid of construction		156,287		56,555		43,421		—	—			256,263
	$	2,405,451		592,459		521,496		128	(438,073	)	$	3,081,461

33

Consolidating balance sheet

	December 31, 2004
(in thousands)	HECO			HELCO		MECO		RHI	Reclassi- fications and Elimina- tions		HECO Consolidated
Assets
Utility plant, at cost
Land	$	25,659		3,019		4,317		—	—		$	32,995
Plant and equipment		2,204,909		714,316		654,491		—	—			3,573,716
Less accumulated depreciation		(849,031	)	(253,294	)	(259,378	)	—	—			(1,361,703	)
Plant acquisition adjustment, net		—		—		197		—	—			197
Construction in progress		79,532		14,541		8,876		—	—			102,949
Net utility plant		1,461,069		478,582		408,503		—	—			2,348,154
Investment in wholly owned subsidiaries, at equity		376,212		—		—		—	(376,212	)[2]		—
Current assets
Cash and equivalents		9		3		17		298	—			327
Advances to affiliates		34,850		—		7,750		—	(42,600	)[1]		—
Customer accounts receivable, net		68,062		18,152		15,793		—	—			102,007
Accrued unbilled revenues, net		55,587		12,898		10,543		—	—			79,028
Other accounts receivable, net		3,755		1,050		1,280		—	414	[1]		6,499
Fuel oil stock, at average cost		39,420		7,805		11,345		—	—			58,570
Materials & supplies, at average cost		11,540		2,730		9,498		—	—			23,768
Prepayments and other		88,255		16,340		9,750		—	—			114,345
Total current assets		301,478		58,978		65,976		298	(42,186	)		384,544
Other long-term assets
Regulatory assets		79,049		15,636		13,945		—	—			108,630
Unamortized debt expense		9,884		2,474		2,366		—	—			14,724
Other		16,211		4,293		3,059		—	—			23,563
Total other long-term assets		105,144		22,403		19,370		—	—			146,917
	$	2,243,903		559,963		493,849		298	(418,398	)	$	2,879,615
Capitalization and liabilities
Capitalization
Common stock equity	$	1,017,104		186,505		189,413		294	(376,212	)[2]	$	1,017,104
Cumulative preferred stock–not subject to mandatory redemption		22,293		7,000		5,000		—	—			34,293
Long-term debt, net		468,049		130,908		153,778		—	—			752,735
Total capitalization		1,507,446		324,413		348,191		294	(376,212	)		1,804,132
Current liabilities
Short-term borrowings-nonaffiliates		76,611		—		—		—	—			76,611
Short-term borrowings-affiliate		19,707		34,850		—		—	(42,600	)[1]		11,957
Accounts payable		66,582		17,530		9,903		—	—			94,015
Interest and preferred dividends payable		8,142		1,240		1,457		—	(101	)[1]		10,738
Taxes accrued		64,966		18,301		22,658		—	—			105,925
Other		23,691		5,265		5,506		4	515	[1]		34,981
Total current liabilities		259,699		77,186		39,524		4	(42,186	)		334,227
Deferred credits and other liabilities
Deferred income taxes		146,812		23,590		18,791		—	—			189,193
Regulatory liabilities		131,915		38,022		27,152		—	—			197,089
Unamortized tax credits		30,392		11,306		11,510		—	—			53,208
Other		23,317		29,405		13,539		—	—			66,261
Total deferred credits and other liabilities		332,436		102,323		70,992		—	—			505,751
Contributions in aid of construction		144,322		56,041		35,142		—	—			235,505
	$	2,243,903		559,963		493,849		298	(418,398	)	$	2,879,615

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Consolidating statement of income

	Year ended December 31, 2005
(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and Elimina- tions		HECO Consolidated
Operating revenues	$	1,204,220		294,411		303,079		—		—		$	1,801,710
Operating expenses
Fuel oil		420,521		65,272		153,857		—		—			639,650
Purchased power		339,120		102,744		16,256		—		—			458,120
Other operation		117,818		26,427		28,717		—		—			172,962
Maintenance		52,547		16,504		13,191		—		—			82,242
Depreciation		70,687		27,177		25,006		—		—			122,870
Taxes, other than income taxes		112,082		27,205		28,008		—		—			167,295
Income taxes		26,144		7,535		11,350		—		—			45,029
		1,138,919		272,864		276,385		—		—			1,688,168
Operating income		65,301		21,547		26,694		—		—			113,542
Other income
Allowance for equity funds used during construction		4,031		174		900		—		—			5,105
Equity in earnings of subsidiaries		30,952		—		—		—		(30,952	)[2]		—
Other, net		4,254		526		626		(176	)	(1,692	)[1]		3,538
		39,237		700		1,526		(176	)	(32,644	)		8,643
Income before interest and other charges		104,538		22,247		28,220		(176	)	(32,644	)		122,185
Interest and other charges
Interest on long-term debt		26,886		7,256		8,921		—		—			43,063
Amortization of net bond premium and expense		1,379		413		420		—		—			2,212
Other interest charges		3,966		1,474		385		—		(1,692	)[1]		4,133
Allowance for borrowed funds used during construction		(1,575	)	(53	)	(392	)	—		—			(2,020	)
Preferred stock dividends of subsidiaries		—		—		—		—		915	[3]		915
		30,656		9,090		9,334		—		(777	)		48,303
Income before preferred stock dividends of HECO		73,882		13,157		18,886		(176	)	(31,867	)		73,882
Preferred stock dividends of HECO		1,080		534		381		—		(915	)[3]		1,080
Net income for common stock	$	72,802		12,623		18,505		(176	)	(30,952	)	$	72,802

Consolidating statement of retained earnings

	Year ended December 31, 2005
(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and Elimina- tions		HECO Consolidated
Retained earnings, beginning of period	$	632,779		85,861		94,492		(187	)	(180,166	)[2]	$	632,779
Net income for common stock		72,802		12,623		18,505		(176	)	(30,952	)[2]		72,802
Common stock dividends		(50,895	)	(9,721	)	(13,728	)	—		23,449	[2]		(50,895	)
Retained earnings, end of period	$	654,686		88,763		99,269		(363	)	(187,669	)	$	654,686

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Consolidating statement of income

	Year ended December 31, 2004
(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and Elimina- tions		HECO Consolidated
Operating revenues	$	1,053,100		241,630		252,145		—		—		$	1,546,875
Operating expenses
Fuel oil		335,281		38,072		110,070		—		—			483,423
Purchased power		295,963		91,024		11,849		—		—			398,836
Other operation		106,138		24,572		26,488		—		—			157,198
Maintenance		47,847		15,145		14,321		—		—			77,313
Depreciation		69,467		21,163		24,290		—		—			114,920
Taxes, other than income taxes		97,974		22,391		23,469		—		—			143,834
Income taxes		29,484		8,204		12,371		—		—			50,059
		982,154		220,571		222,858		—		—			1,425,583
Operating income		70,946		21,059		29,287		—		—			121,292
Other income
Allowance for equity funds used during construction		5,226		162		406		—		—			5,794
Equity in earnings of subsidiaries		31,746		—		—		—		(31,746	)[2]		—
Other, net		3,652		210		(43	)	(53	)	(634	)[1]		3,132
		40,624		372		363		(53	)	(32,380	)		8,926
Income before interest and other charges		111,570		21,431		29,650		(53	)	(32,380	)		130,218
Interest and other charges
Interest on long-term debt		26,566		7,184		8,793		—		—			42,543
Amortization of net bond premium and expense		1,464		403		422		—		—			2,289
Other interest charges		3,595		1,083		712		—		(634	)[1]		4,756
Allowance for borrowed funds used during construction		(2,312	)	(75	)	(155	)	—		—			(2,542	)
Preferred stock dividends of subsidiaries		—		—		—		—		915	[3]		915
		29,313		8,595		9,772		—		281			47,961
Income before preferred stock dividends of HECO		82,257		12,836		19,878		(53	)	(32,661	)		82,257
Preferred stock dividends of HECO		1,080		534		381		—		(915	)[3]		1,080
Net income for common stock	$	81,177		12,302		19,497		(53	)	(31,746	)	$	81,177

Consolidating statement of retained earnings

	Year ended December 31, 2004
(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and Elimina- tions		HECO Consolidated
Retained earnings, beginning of period	$	563,215		74,629		92,909		(134	)	(167,404	)[2]	$	563,215
Net income for common stock		81,177		12,302		19,497		(53	)	(31,746	)[2]		81,177
Common stock dividends		(11,613	)	(1,070	)	(17,914	)	—		18,984	[2]		(11,613	)
Retained earnings, end of period	$	632,779		85,861		94,492		(187	)	(180,166	)	$	632,779

36

Consolidating statement of income

	Year ended December 31, 2003
(in thousands)	HECO			HELCO		MECO		RHI		HECO Capital Trust I	HECO Capital Trust II	Reclassi- fications and Elimina- tions		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		RHI		HECO Capital Trust I		HECO Capital Trust II		Reclassi- fications and Elimina- tions		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

37

Consolidating statement of cash flows

	Year ended December 31, 2005
(in thousands)	HECO			HELCO		MECO		RHI		Elimination addition to (deduction from) cash flows		HECO Consolidated
Cash flows from operating activities:
Income before preferred stock dividends of HECO	$	73,882		13,157		18,886		(176	)	(31,867	)[2]	$	73,882
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Equity in earnings		(31,053	)	—		—		—		30,952	[2]		(101	)
Common stock dividends received from subsidiaries		23,550		—		—		—		(23,449	)[2]		101
Depreciation of property, plant and equipment		70,687		27,177		25,006		—		—			122,870
Other amortization		4,350		913		3,216		—		—			8,479
Deferred income taxes		13,381		1,557		4,148		—		—			19,086
Tax credits, net		1,722		1,588		161		—		—			3,471
Allowance for equity funds used during construction		(4,031	)	(174	)	(900	)	—		—			(5,105	)
Changes in assets and liabilities:
Increase in accounts receivable		(20,265	)	(5,222	)	(4,485	)	—		(178	)[1]		(30,150	)
Increase in accrued unbilled revenues		(7,114	)	(1,777	)	(3,402	)	—		—			(12,293	)
Increase in fuel oil stock		(24,889	)	(63	)	(1,928	)	—		—			(26,880	)
Increase in materials and supplies		(2,588	)	(474	)	(144	)	—		—			(3,206	)
Decrease (increase) in regulatory assets		(2,472	)	443		(3,007	)	—		—			(5,036	)
Increase in accounts payable		20,261		1,973		5,952		—		—			28,186
Increase in taxes accrued		19,088		5,951		2,619		—		—			27,658
Decrease (increase) in prepaid pension benefit cost		(1,412	)	367		745		—		—			(300	)
Changes in other assets and liabilities		(11,788	)	(1,943	)	(2,397	)	6		178	[2]		(15,944	)
Net cash provided by (used in) operating activities		121,309		43,473		44,470		(170	)	(24,364	)		184,718
Cash flows from investing activities:
Capital expenditures		(128,127	)	(52,107	)	(37,376	)	—		—			(217,610	)
Contributions in aid of construction		13,439		3,141		4,503		—		—			21,083
Advances from (to) affiliates		(14,850	)	—		2,500		—		12,350	[1]		—
Proceeds from sales of assets		1,680		—		—		—		—			1,680
Net cash used in investing activities		(127,858	)	(48,966	)	(30,373	)	—		12,350			(194,847	)
Cash flows from financing activities:
Common stock dividends		(50,895	)	(9,721	)	(13,728	)	—		23,449	[2]		(50,895	)
Preferred stock dividends		(1,080	)	(534	)	(381	)	—		915	[2]		(1,080	)
Proceeds from issuance of long-term debt		52,462		5,000		2,000		—		—			59,462
Repayment of long-term debt		(40,000	)	(5,000	)	(2,000	)	—		—			(47,000	)
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		45,097		14,850		—		—		(12,350	)[1]		47,597
Other		964		898		(1	)	—		—			1,861
Net cash provided by (used in) financing activities		6,548		5,493		(14,110	)	—		12,014			9,945
Net decrease in cash and equivalents		(1	)	—		(13	)	(170	)	—			(184	)
Cash and equivalents, beginning of year		9		3		17		298		—			327
Cash and equivalents, end of year	$	8		3		4		128		—		$	143

38

Consolidating statement of cash flows

	Year ended December 31, 2004
(in thousands)	HECO			HELCO		MECO		RHI		Elimination addition to (deduction from) cash flows		HECO Consolidated
Cash flows from operating activities:
Income before preferred stock dividends of HECO	$	82,257		12,836		19,878		(53	)	(32,661	)[2]	$	82,257
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Equity in earnings		(31,931	)	—		—		—		31,746	[2]		(185	)
Common stock dividends received from subsidiaries		19,169		—		—		—		(18,984	)[2]		185
Depreciation of property, plant and equipment		69,467		21,163		24,290		—		—			114,920
Other amortization		4,290		776		3,714		—		—			8,780
Deferred income taxes		10,304		3,969		6,511		—		—			20,784
Tax credits, net		2,315		2,435		462		—		—			5,212
Allowance for equity funds used during construction		(5,226	)	(162	)	(406	)	—		—			(5,794	)
Changes in assets and liabilities:
Increase in accounts receivable		(6,560	)	(2,371	)	(3,935	)	—		(1,308	)[1]		(14,174	)
Increase in accrued unbilled revenues		(14,387	)	(2,201	)	(2,068	)	—		—			(18,656	)
Increase in fuel oil stock		(7,360	)	(4,279	)	(3,319	)	—		—			(14,958	)
Increase in materials and supplies		(1,209	)	(194	)	(1,132	)	—		—			(2,535	)
Decrease (increase) in regulatory assets		(560	)	657		(2,521	)	—		—			(2,424	)
Increase (decrease) in accounts payable		17,159		6,937		(2,458	)	—		—			21,638
Increase in taxes accrued		6,404		1,778		4,440		—		—			12,622
Increase in prepaid pension benefit cost		(16,733	)	(4,799	)	(3,565	)	—		—			(25,097	)
Changes in other assets and liabilities		(10,891	)	(1,236	)	(2,899	)	(7	)	1,308	[2]		(13,725	)
Net cash provided by (used in) operating activities		116,508		35,309		36,992		(60	)	(19,899	)		168,850
Cash flows from investing activities:
Capital expenditures		(123,795	)	(49,324	)	(28,117	)	—		—			(201,236	)
Contributions in aid of construction		4,134		2,796		1,592		—		—			8,522
Advances from (to) affiliates		(24,050	)	—		17,750		—		6,300	[1]		—
Investment in unconsolidated subsidiary		(1,846	)	—		—		—		300	[2]		(1,546	)
Distributions from unconsolidated subsidiaries		3,093		—		—		—		—			3,093
Proceeds from sales of assets		650		—		—		—		—			650
Net cash used in investing activities		(141,814	)	(46,528	)	(8,775	)	—		6,600			(190,517	)
Cash flows from financing activities:
Common stock dividends		(11,613	)	(1,070	)	(17,914	)	—		18,984	[2]		(11,613	)
Preferred stock dividends		(1,080	)	(534	)	(381	)	—		915	[2]		(1,080	)
Proceeds from issuance of common stock		—		—		—		300		(300	)[2]		—
Proceeds from issuance of long-term debt		33,097		10,000		10,000		—		—			53,097
Repayment of long-term debt		(63,093	)	(20,000	)	(20,000	)	—		—			(103,093	)
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		64,818		24,050		—		—		(6,300	)[1]		82,568
Other		3,177		(1,228	)	8		—		—			1,957
Net cash provided by (used in) financing activities		25,306		11,218		(28,287	)	300		13,299			21,836
Net increase (decrease) in cash and equivalents		—		(1	)	(70	)	240		—			169
Cash and equivalents, beginning of year		9		4		87		58		—			158
Cash and equivalents, end of year	$	9		3		17		298		—		$	327

39

Consolidating statement of cash flows

	Year ended December 31, 2003
(in thousands)	HECO			HELCO		MECO		RHI		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
Increase in prepaid pension benefit cost		(7,500	)	(2,127	)	(1,096	)	—		—		—		—			(10,723	)
Changes in other assets and liabilities		(7,335	)	1,218		610		11		—		—		8,023	[2]		2,527
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

40

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 prior to 2004 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 III, which trust holds the 2004 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 2005 and 2004 follows:

	Quarters ended								Year ended Dec. 31
2005	March 31		June 30		Sept. 30		Dec. 31
(in thousands)
Operating revenues	$	373,690	$	428,807	$	489,877	$	509,336	$	1,801,710
Operating income (1)		23,065		29,624		32,614		28,239		113,542
Net income for common stock (1)		12,385		19,644		22,587		18,186		72,802
	Quarters ended								Year ended Dec. 31
2004	March 31		June 30		Sept. 30		Dec. 31
(in thousands)
Operating revenues	$	345,944	$	369,393	$	408,766	$	422,772	$	1,546,875
Operating income (2)		30,839		31,122		34,865		24,466		121,292
Net income for common stock (2)		20,023		21,735		26,175		13,244		81,177

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

(1) For 2005, the amounts for the fourth quarter include $10 million of interim rate relief for HECO.

(2) For 2004, the amounts for the fourth quarter include $16 million higher other operation and maintenance expenses due in part to larger scope and timing of overhauls, more repairs and maintenance, information technology system enhancements expenses, additions to insurance reserves and expenses related to compliance with the Sarbanes-Oxley Act of 2002.

41