(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that each registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc. is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes x No ¨

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc. is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨No x

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨No x

Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of the latest practicable date.

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

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

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


(dollars in thousands)	June 30, 2005			December 31, 2004			September 30, 2005			December 31, 2004
Assets
Cash and equivalents	$	168,330		$	132,138		$	165,395		$	132,138
Federal funds sold		58,064			41,491			67,080			41,491
Accounts receivable and unbilled revenues, net		212,428			208,533			239,133			208,533
Available-for-sale investment and mortgage-related securities		1,913,565			2,034,091			1,929,433			2,034,091
Available-for-sale mortgage-related securities pledged for repurchase agreements		821,274			919,281			813,136			919,281
Held-to-maturity investment in Federal Home Loan Bank of Seattle stock (estimated fair value $97,764 and $97,365)		97,764			97,365
Investment in Federal Home Loan Bank of Seattle stock (estimated fair value $97,764 and $97,365)								97,764			97,365
Loans receivable, net		3,427,687			3,249,191			3,501,540			3,249,191
Property, plant and equipment, net of accumulated depreciation of $1,489,145 and $1,434,840		2,452,775			2,422,303
Property, plant and equipment, net of accumulated depreciation of $1,516,119 and $1,434,840								2,488,603			2,422,303
Regulatory assets		109,063			108,630			109,518			108,630
Other		455,981			414,971			474,220			414,971
Goodwill and other intangibles		90,140			91,263			89,696			91,263

	$	9,807,071		$	9,719,257		$	9,975,518		$	9,719,257

Liabilities and stockholders’ equity
Liabilities
Accounts payable	$	146,022		$	153,943		$	182,470		$	153,943
Deposit liabilities		4,453,322			4,296,172			4,551,837			4,296,172
Short-term borrowings		126,888			76,611			120,642			76,611
Securities sold under agreements to repurchase		667,463			811,438			681,427			811,438
Advances from Federal Home Loan Bank		1,018,200			988,231			1,008,200			988,231
Long-term debt, net		1,168,079			1,166,735			1,173,009			1,166,735
Deferred income taxes		226,845			229,765			234,339			229,765
Regulatory liabilities		208,172			197,089			213,230			197,089
Contributions in aid of construction		236,330			235,505			242,505			235,505
Other		305,371			318,418			320,208			318,418

		8,556,692			8,473,907			8,727,867			8,473,907

Minority interests
Preferred stock of subsidiaries - not subject to mandatory redemption		34,293			34,405			34,293			34,405

Stockholders’ equity
Preferred stock, no par value, authorized 10,000,000 shares; issued: none		—			—			—			—
Common stock, no par value, authorized 100,000,000 shares; issued and outstanding: 80,934,009 shares and 80,687,350 shares		1,017,272			1,010,090
Common stock, no par value, authorized 100,000,000 shares; issued and outstanding: 80,955,756 shares and 80,687,350 shares								1,018,170			1,010,090
Retained earnings		210,573			208,998			222,969			208,998
Accumulated other comprehensive loss		(11,759	)		(8,143	)
Accumulated other comprehensive loss, net of tax benefits								(27,781	)		(8,143	)

		1,216,086			1,210,945			1,213,358			1,210,945

	$	9,807,071		$	9,719,257		$	9,975,518		$	9,719,257

See accompanying “Notes to ~~HEI’s~~ Consolidated Financial ~~Statements.”~~Statements” for HEI.


	Three months ended June 30,						Six months ended June 30,
(in thousands, except per share amounts and ratio of earnings to fixed charges)													Three months ended September 30,						Nine months ended September 30,
	2005			2004			2005			2004			2005			2004			2005			2004
Revenues
Electric utility	$	429,730		$	370,605		$	804,505		$	717,218		$	491,339		$	410,077		$	1,295,844		$	1,127,295
Bank		91,946			89,982			189,170			179,240			97,431			90,296			286,601			269,536
Other		586			1,211			1,215			2,450			7,145			6,386			8,360			8,836

		522,262			461,798			994,890			898,908			595,915			506,759			1,590,805			1,405,667

Expenses
Electric utility		387,083			324,691			730,252			627,164			443,806			357,364			1,174,058			984,528
Bank		69,744			66,971			138,015			130,121			71,493			63,765			209,508			193,886
Other		3,986			3,190			8,503			6,840			3,377			3,944			11,880			10,784

		460,813			394,852			876,770			764,125			518,676			425,073			1,395,446			1,189,198

Operating income (loss)
Electric utility		42,647			45,914			74,253			90,054			47,533			52,713			121,786			142,767
Bank		22,202			23,011			51,155			49,119			25,938			26,531			77,093			75,650
Other		(3,400	)		(1,979	)		(7,288	)		(4,390	)		3,768			2,442			(3,520	)		(1,948	)

		61,449			66,946			118,120			134,783			77,239			81,686			195,359			216,469

Interest expense—other than bank		(19,130	)		(19,106	)		(37,965	)		(40,553	)		(18,990	)		(18,376	)		(56,955	)		(58,929	)
Allowance for borrowed funds used during construction		475			733			902			1,377			558			859			1,460			2,236
Preferred stock dividends of subsidiaries		(474	)		(475	)		(950	)		(950	)		(471	)		(475	)		(1,421	)		(1,425	)
Allowance for equity funds used during construction		1,182			1,673			2,269			3,122			1,406			1,934			3,675			5,056

Income before income taxes		43,502			49,771			82,376			97,779
Income from continuing operations before income taxes														59,742			65,628			142,118			163,407
Income taxes		15,167			38,533			29,946			55,609			22,252			24,869			52,198			80,478

Income from continuing operations		28,335			11,238			52,430			42,170			37,490			40,759			89,920			82,929
Discontinued operations-loss on disposal, net of income taxes		(755	)		—			(755	)		—
Discontinued operations-gain (loss) on disposal, net of income taxes														—			1,913			(755	)		1,913

Net income	$	27,580		$	11,238		$	51,675		$	42,170		$	37,490		$	42,672		$	89,165		$	84,842

Basic earnings (loss) per common share operations
Basic earnings (loss) per common share
Continuing operations	$	0.35		$	0.14		$	0.65		$	0.54		$	0.46		$	0.51		$	1.11		$	1.05
Discontinued operations		(0.01	)		—			(0.01	)		—			—			0.02			(0.01	)		0.02

	$	0.34		$	0.14		$	0.64		$	0.54		$	0.46		$	0.53		$	1.10		$	1.07

Diluted earnings (loss) per common share
Continuing operations	$	0.35		$	0.14		$	0.65		$	0.53		$	0.46		$	0.51		$	1.11		$	1.05
Discontinued operations		(0.01	)		—			(0.01	)		—			—			0.02			(0.01	)		0.02

	$	0.34		$	0.14		$	0.64		$	0.53		$	0.46		$	0.53		$	1.10		$	1.07

Dividends per common share	$	0.31		$	0.31		$	0.62		$	0.62		$	0.31		$	0.31		$	0.93		$	0.93

Weighted-average number of common shares outstanding		80,814			80,350			80,741			78,544			80,903			80,509			80,795			79,204
Dilutive effect of stock options and dividend equivalents		399			357			404			351			451			319			397			245

Adjusted weighted-average shares		81,213			80,707			81,145			78,895			81,354			80,828			81,192			79,449

Ratio of earnings to fixed charges (SEC method)
Excluding interest on ASB deposits								2.07			2.20									2.23			2.37

Including interest on ASB deposits								1.81			1.92									1.93			2.05

See accompanying “Notes to ~~HEI’s~~ Consolidated Financial ~~Statements.”~~


	Common stock			Retained earnings			Accumulated other comprehensive income (loss)				Total
(in thousands, except per share amounts)							Accumulated other comprehensive income (loss)			Common stock				Retained earnings			Accumulated other comprehensive income (loss)				Total
(in thousands, except per share amounts)	Shares	Amount		Retained earnings		Retained earnings			Accumulated other comprehensive income (loss)		Total			Retained earnings			Accumulated other comprehensive income (loss)			Total					Shares		Amount
Balance, December 31, 2004	80,687	$	1,010,090			Retained earnings			Accumulated other comprehensive income (loss)		80,687		$	1,010,090	$	208,998			$	Total		(8,143	)		$	1,210,945
Comprehensive income:
Net income	—		—		51,675			—				51,675		—		—			89,165				—			89,165
Net unrealized losses on securities:
Net unrealized losses on securities arising during the period, net of tax benefits of $4,881	—		—		—			(3,510	)			(3,510	)
Net unrealized losses on securities arising during the period, net of tax benefits of $15,459														—		—			—				(19,532	)		(19,532	)
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $70	—		—		—			(106	)			(106	)	—		—			—				(106	)		(106	)

Comprehensive income (loss)	—		—		51,675			(3,616	)			48,059		—		—			89,165				(19,638	)		69,527

Issuance of common stock, net	247		7,182		—			—				7,182		269		8,080			—				—			8,080
Common stock dividends ($0.62 per share)	—		—		(50,100	)		—				(50,100	)
Common stock dividends ($0.93 per share)														—		—			(75,194	)			—			(75,194	)

Balance, June 30, 2005	80,934	$	1,017,272	$	210,573		$	(11,759	)		$	1,216,086
Balance, September 30, 2005														80,956	$	1,018,170		$	222,969			$	(27,781	)	$	1,213,358

Balance, December 31, 2003	75,838	$	888,431	$	197,774		$	2,826			$	1,089,031		75,838	$	888,431		$	197,774			$	2,826		$	1,089,031
Comprehensive income:
Net income	—		—		42,170			—				42,170		—		—			84,842				—			84,842
Net unrealized losses on securities:
Net unrealized losses arising during the period, net of tax benefits of $13,344	—		—		—			(28,609	)			(28,609	)
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $6	—		—		—			(10	)			(10	)
Net unrealized losses arising during the period, net of tax benefits of $2,621														—		—			—				(3,969	)		(3,969	)
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $2,002														—		—			—				(3,535	)		(3,535	)
Minimum pension liability adjustment, net of tax benefits of $19	—		—		—			1				1		—		—			—				1			1

Comprehensive income (loss)	—		—		42,170			(28,618	)			13,552		—		—			84,842				(7,503	)		77,339

Issuance of common stock, net	4,536		115,898		—			—				115,898		4,726		119,323			—				—			119,323
Common stock dividends ($0.62 per share)	—		—		(48,480	)		—				(48,480	)
Common stock dividends ($0.93 per share)														—		—			(73,446	)			—			(73,446	)

Balance, June 30, 2004	80,374	$	1,004,329	$	191,464		$	(25,792	)		$	1,170,001
Balance, September 30, 2004														80,564	$	1,007,754		$	209,170			$	(4,677	)	$	1,212,247

See accompanying “Notes to ~~HEI’s~~ Consolidated Financial ~~Statements.”~~Statements” for HEI.


Six months ended June 30	2005			2004
							Nine months ended September 30
(in thousands)							2005			2004
Cash flows from operating activities
Income from continuing operations	$	52,430		$	42,170		$	89,920		$	82,929
Adjustments to reconcile income from continuing operations to net cash provided by operating activities
Depreciation of property, plant and equipment		66,974			62,826			100,391			94,065
Other amortization		5,861			9,646			7,565			14,135
Provision for loan losses		(3,100	)		(4,600	)
Reversal of allowance for loan losses								(3,100	)		(8,400	)
Deferred income taxes		2,066			(2,793	)		19,843			15,152
Allowance for equity funds used during construction		(2,269	)		(3,122	)		(3,675	)		(5,056	)
Gain on sale of income notes								—			(5,607	)
Changes in assets and liabilities
Decrease (increase) in accounts receivable and unbilled revenues, net		(3,895	)		3,410
Increase in accounts receivable and unbilled revenues, net								(30,600	)		(15,806	)
Increase in tax deposit		(30,000	)		—			(30,000	)		—
Increase (decrease) in accounts payable		(7,921	)		20,316
Increase (decrease) in taxes accrued		(5,406	)		42,647
Increase in accounts payable								28,527			40,818
Increase in taxes accrued								13,439			55,968
Changes in other assets and liabilities		(4,573	)		5,221			(35,931	)		(33,802	)

Net cash provided by operating activities		70,167			175,721			156,379			234,396

Cash flows from investing activities
Available-for-sale mortgage-related securities purchased		(174,436	)		(633,813	)		(411,811	)		(863,790	)
Principal repayments on available-for-sale mortgage-related securities		353,425			431,484			555,640			606,356
Proceeds from sale of available-for-sale mortgage-related securities		28,039			11,427			28,039			45,207
Originations and purchases of loans held for investment		(645,019	)		(578,115	)
Principal repayments on loans held for investment		465,693			598,446
Net decrease (increase) in loans held for investment								(243,452	)		4,933
Proceeds from sale of real estate acquired in settlement of loans		—			580			—			749
Capital expenditures		(86,146	)		(86,643	)		(146,696	)		(141,459	)
Contributions in aid of construction		5,444			3,448			10,274			5,857
Distributions from unconsolidated subsidiaries		—			24,379			—			24,379
Other		1,144			(178	)		1,197			9,889

Net cash used in investing activities		(51,856	)		(228,985	)		(206,809	)		(307,879	)

Cash flows from financing activities
Net increase in deposit liabilities		157,150			51,978			255,665			156,159
Net increase in short-term borrowings with maturities of three months or less		50,277			14,197			44,031			8,392
Net increase in retail repurchase agreements		8,713			6,645			17,717			20,428
Proceeds from securities sold under agreements to repurchase		510,205			513,350			674,056			608,650
Repayments of securities sold under agreements to repurchase		(663,300	)		(483,000	)		(822,950	)		(672,650	)
Proceeds from advances from Federal Home Loan Bank		173,000			50,200			173,000			129,200
Principal payments on advances from Federal Home Loan Bank		(143,031	)		(102,201	)		(153,031	)		(126,200	)
Proceeds from issuance of long-term debt		53,643			102,073			58,525			102,525
Repayment of long-term debt		(53,000	)		(223,165	)		(53,000	)		(223,165	)
Net proceeds from issuance of common stock		2,918			106,000			3,232			108,356
Common stock dividends		(50,073	)		(43,942	)		(75,153	)		(68,895	)
Other		(10,212	)		(8,234	)		(10,354	)		(5,099	)

Net cash provided by (used in) financing activities		36,290			(16,099	)
Net cash provided by financing activities								111,738			37,701

Net cash provided by (used in) discontinued operations		(1,836	)		1,943			(2,462	)		3,366

Net increase (decrease) in cash and equivalents and federal funds sold		52,765			(67,420	)		58,846			(32,416	)
Cash and equivalents and federal funds sold, beginning of period		173,629			279,988			173,629			279,988

Cash and equivalents and federal funds sold, end of period	$	226,394		$	212,568		$	232,475		$	247,572

See accompanying “Notes to ~~HEI’s~~ Consolidated Financial ~~Statements.”~~Statements” for HEI.

The accompanying unaudited consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (GAAP) for interim financial information, the instructions to SEC Form 10-Q and Article 10 of Regulation S–X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenues and expenses for the period. Actual results could differ significantly from those estimates. The accompanying unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and the notes thereto included in HEI’s Form 10-K for the year ended December 31, 2004 and the unaudited consolidated financial statements and the notes thereto in HEI’s Quarterly ~~Report~~Reports on SEC Form 10-Q for the ~~quarter~~quarters ended March 31, 2005 and June 30, 2005.

In the opinion of HEI’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to present fairly the Company’s financial position as of ~~June~~September 30, 2005 and December 31, 2004 and the results of its operations for the three and ~~six~~nine months ended ~~June~~September 30, 2005 and 2004 and its cash flows for the ~~six~~nine months ended ~~June~~September 30, 2005 and 2004. All such adjustments are of a normal recurring nature, unless otherwise disclosed in this Form 10–Q or other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year. When required, certain reclassifications are made to the prior period’s consolidated financial statements to conform to the current presentation. For example, assets and liabilities at December 31, 2004 have been restated for the reclassification of regulatory assets from “Regulatory liabilities, net” to “Regulatory assets.”

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

Intercompany electric sales of consolidated HECO to the bank and “other” segments are not eliminated because those segments would need to purchase electricity from another source if it were not provided by consolidated HECO, the profit on such sales is nominal and the elimination of electric sales revenues and expenses could distort segment operating income and net income.

Bank fees that ASB charges the electric utility and “other” segments are not eliminated because those segments would pay fees to another financial institution if they were to bank with another institution, the profit on such fees is nominal and the elimination of bank fee income and expenses could distort segment operating income and net income.

In June 2004, ASB recorded a cumulative after-tax charge to net income of $24 million for an unfavorable tax ruling involving its real estate investment trust subsidiary, which was settled in December 2004.

For HECO’s consolidated financial information, including its commitments and contingencies, see pages 13 through ~~31.~~32.


(in thousands)	June 30, 2005			December 31, 2004			September 30, 2005			December 31, 2004
Assets
Cash and equivalents	$	161,285		$	120,295		$	157,167		$	120,295
Federal funds sold		58,064			41,491			67,080			41,491
Available-for-sale investment and mortgage-related securities		1,913,565			2,034,091			1,929,433			2,034,091
Available-for-sale mortgage-related securities pledged for repurchase agreements		821,274			919,281			813,136			919,281
Held-to-maturity investment in Federal Home Loan Bank of Seattle stock (estimated fair value $97,764 and $97,365)		97,764			97,365
Investment in Federal Home Loan Bank of Seattle stock (estimated fair value $97,764 and $97,365)								97,764			97,365
Loans receivable, net		3,427,687			3,249,191			3,501,540			3,249,191
Other		246,770			213,528			245,649			213,528
Goodwill and other intangibles		90,140			91,263			89,696			91,263

	$	6,816,549		$	6,766,505		$	6,901,465		$	6,766,505

Liabilities and stockholder’s equity
Deposit liabilities–noninterest bearing	$	586,154		$	558,958		$	611,897		$	558,958
Deposit liabilities–interest bearing		3,867,168			3,737,214			3,939,940			3,737,214
Securities sold under agreements to repurchase		667,463			811,438			681,427			811,438
Advances from Federal Home Loan Bank		1,018,200			988,231			1,008,200			988,231
Other		112,161			110,938			101,857			110,938

		6,251,146			6,206,779			6,343,321			6,206,779

Minority interests		—			3,415			—			3,415

Common stock		321,173			320,501			321,476			320,501
Retained earnings		255,056			243,001			263,516			243,001
Accumulated other comprehensive loss		(10,826	)		(7,191	)
Accumulated other comprehensive loss, net of tax benefits								(26,848	)		(7,191	)

		565,403			556,311			558,144			556,311

	$	6,816,549		$	6,766,505		$	6,901,465		$	6,766,505


	Three months ended June 30,					Six months ended June 30,						Three months ended September 30,					Nine months ended September 30,
(in thousands)	2005		2004			2005			2004			2005		2004			2005			2004
Interest and dividend income
Interest and fees on loans	$	50,657	$	45,832		$	99,170		$	92,241		$	52,649	$	45,504		$	151,819		$	137,745
Interest on mortgage-related securities		26,636		27,559			60,464			54,636			29,711		29,608			90,175			84,244
Interest and dividends on investment securities		887		1,665			1,922			3,413			1,178		1,619			3,100			5,032

		78,180		75,056			161,556			150,290			83,538		76,731			245,094			227,021

Interest expense
Interest on deposit liabilities		12,460		11,464			24,477			23,674			13,355		11,660			37,832			35,334
Interest on Federal Home Loan Bank advances		11,291		10,347			22,116			20,844			11,393		11,143			33,509			31,987
Interest on securities sold under repurchase agreements		5,602		5,231			12,525			10,477			5,885		5,345			18,410			15,822

		29,353		27,042			59,118			54,995			30,633		28,148			89,751			83,143

Net interest income		48,827		48,014			102,438			95,295			52,905		48,583			155,343			143,878
Recovery of loan losses		—		(3,000	)		(3,100	)		(4,600	)
Reversal of allowance for loan losses													—		(3,800	)		(3,100	)		(8,400	)

Net interest income after recovery of loan losses		48,827		51,014			105,538			99,895
Net interest income after reversal of allowance for loan losses													52,905		52,383			158,443			152,278

Other income
Fees from other financial services		6,333		6,160			12,196			11,742			6,512		5,980			18,708			17,722
Fee income on deposit liabilities		4,092		4,276			8,263			8,657			4,311		4,619			12,574			13,276
Fee income on other financial products		2,154		2,646			4,589			5,622			2,191		2,328			6,780			7,950
Fee income on loans serviced for others, net		114		907			329			577
Gain on sale of securities		175		—			175			16
Gain (loss) on sale of securities													—		(86	)		175			(70	)
Other income		898		937			2,062			2,336			879		724			3,270			3,637

		13,766		14,926			27,614			28,950			13,893		13,565			41,507			42,515

General and administrative expenses
Compensation and employee benefits		17,441		15,704			34,068			31,459			17,275		16,044			51,343			47,503
Occupancy		4,088		4,273			8,106			8,529			4,356		4,201			12,462			12,730
Equipment		3,302		3,378			6,701			7,045			3,413		3,319			10,114			10,364
Data processing		2,503		2,777			5,548			5,600			2,491		2,949			8,039			8,549
Consulting and other services		3,941		3,190			7,608			5,721
Services													3,986		3,292			11,594			9,013
Interest on income taxes		406		5,324			3,082			5,324			14		461			3,096			5,785
Other		8,710		8,283			16,884			16,048			9,325		9,151			26,209			25,199

		40,391		42,929			81,997			79,726			40,860		39,417			122,857			119,143

Income before minority interests and income taxes		22,202		23,011			51,155			49,119			25,938		26,531			77,093			75,650
Minority interests		18		23			45			49			—		24			45			73
Income taxes		8,631		28,584			19,793			37,387			10,027		9,776			29,820			47,163

Income (loss) before preferred stock dividends		13,553		(5,596	)		31,317			11,683
Income before preferred stock dividends													15,911		16,731			47,228			28,414
Preferred stock dividends		1		1,353			4			2,705			—		1,353			4			4,058

Net income (loss) for common stock	$	13,552	$	(6,949	)	$	31,313		$	8,978
Net income for common stock												$	15,911	$	15,378		$	47,224		$	24,356

In December 2004, ASB’s capital structure changed when ASB redeemed its preferred stock held by HEIDI ($75 million) and HEIDI infused common equity into ASB ($75 million).

At ~~June~~September 30, 2005, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of ~~$1.0~~$1.1 billion.

In the first quarter of 2005, ASB recorded a $3 million reserve for potential interest on the disputed timing of dividend income ~~recognition.~~recognition for federal income tax purposes. In the second quarter of 2005, ASB made a $30 million deposit primarily to stop the further accrual of interest on the disputed timing of dividend income recognition related to a change in ASB’s 2000 and 2001 tax year-ends. ASB believes it has adequately provided for this disputed issue and other minor unresolved income tax issues with federal and state tax authorities and related interest.

In 1998, ASB formed a subsidiary, ASB Realty Corporation, which elected to be taxed as a real estate investment trust (REIT). This reorganization had reduced Hawaii bank franchise taxes as a result of ASB taking a dividends received deduction on dividends paid to it by ASB Realty Corporation. The State of Hawaii Department of Taxation (DOT) challenged ASB’s position on the dividends received deduction and issued notices of tax assessment for 1999 through 2001. ~~In 2002,~~ ASB filed an appeal with the State Board of Review, First Taxation District (Board) ~~and in 2003, the Board~~, which issued its decision in favor of the ~~DOT and~~DOT. ASB filed a notice of appeal with the Hawaii Tax Appeal ~~Court.~~

~~In June 2004, the Hawaii Tax Appeal~~ Court, which issued its decision in favor of the DOT ~~for tax assessed years 1999 through 2001. ASB appealed the decision to the Hawaii Supreme Court, which appeal was dismissed as part of a settlement described below.~~in June 2004. As a result of the ~~Hawaii Tax Appeal Court’s~~ decision, ASB recorded a cumulative after-tax charge to net income in the second quarter of 2004 of $24 million ($21 million for the bank franchise taxes and $3 million for interest).

On ASB appealed the decision to the Hawaii Supreme Court, which appeal was dismissed as part of a settlement on December 31, ~~2004,~~2004. ASB agreed to settle its dispute with the DOT and close the tax years 1999 through 2004 (relating to the financial performance of ASB for the years 1998 through 2003) for purposes of audit, examination, assessment, refund and judicial review. Under the terms of the settlement, ASB agreed to pay the DOT $12 million, in addition to $17 million previously paid under protest, dismiss its appeal to the Hawaii Supreme Court and not take the dividends received deduction in future years. As a result, ASB recognized $3 million in additional net income in the fourth quarter of 2004, representing a partial reversal of the $24 million previously charged against net income. ASB Realty Corporation was dissolved in the second quarter of 2005, with substantially all of its assets being distributed to ASB.

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

In the third quarter of 2004, the HEIPC Group transferred its interest in a China joint venture to its partner and another entity for $3 million and recorded a gain on disposal, net of income taxes, of $2 million. The HEIPC Group ~~is continuing to pursue~~pursued recovery of a significant portion of its losses through arbitration of its claims under a political risk insurance policy. In the second quarter of 2005, HEIPC increased its reserve for future expenses by $1 million primarily due to higher than expected arbitration costs. ~~Post-hearing briefs were filed in August 2005. A~~In the fourth quarter of 2005, the arbitration panel issued its decision ~~is possible prior to year-end; however, management cannot predict when a final decision will be rendered or~~denying HEIPC’s claims for recovery of losses under the ~~outcome of its claims.~~political risk insurance policy.

As of ~~June~~September 30, 2005, the remaining net assets of the discontinued international power operations amounted to ~~$11~~$12 million (included in “Other” assets) and consisted primarily of deferred taxes receivable, reduced by a reserve for losses from operations during the phase-out period (primarily for legal fees). If the HEIPC Group is successful in pursuing its insurance claims in connection with its China joint venture interest, any such recovery would be recorded as a gain on disposal of discontinued operations. Further losses may be sustained if the expenditures made in pursuing its insurance claims in connection with the China joint venture interest exceed the total of any recovery ultimately achieved and the amount provided for in HEI’s reserve for discontinued operations.

(6) ~~HEI common stock sale and redemption of HEI-obligated trust preferred securities; HEI medium-term notes; HECO-obligated trust preferred securities~~

Hawaiian Electric Industries Capital Trust I (the Trust) was a Delaware statutory trust and financing entity which issued, in 1997, $100 million of 8.36% Trust Originated Preferred Securities to the public. In March 2004, HEI completed the issuance and sale of 2 million shares of its common stock (pre-split) in a registered public offering. HEI used the net proceeds from the sale, along with other corporate funds, to effect the redemption of the 8.36% Trust Originated Preferred Securities in April 2004. The Trust was dissolved and terminated in 2004.

On March 17, 2004, HEI sold $50 million of 4.23% notes, due March 15, 2011, under its registered medium-term note program. The net proceeds from this sale were ultimately used to make short-term loans to HECO, to assist HECO and Hawaii Electric Light Company, Inc. (HELCO) in redeeming in April 2004 the 7.30% Cumulative Quarterly Income Preferred Securities, Series 1998, and for other general corporate purposes. HECO has repaid those short-term loans primarily with funds saved from reducing dividends to HEI in 2004.

~~See Note 2 of “Notes to HECO’s Consolidated Financial Statements” for a discussion of the electric utilities’ trust preferred securities.~~

~~For~~In the ~~six~~first nine months ~~ended June 30,~~of 2005, ASB paid $6 million and HECO paid $5$8 million of contributions to the retirement benefit plans, compared to $1 million and $5$22 million, respectively, in the first ~~half~~nine months of 2004. The Company’s current estimate of contributions to the retirement benefit plans in 2005 is $17 million, compared to contributions of $37 million in 2004. The balance of the estimated 2005 contributions is expected to be made primarily by the electric utilities.


	Three months ended June 30												Six months ended June 30												Three months ended September 30												Nine months ended September 30
	Pension benefits						Other benefits						Pension benefits						Other benefits						Pension benefits						Other benefits						Pension benefits						Other benefits
(in thousands)	2005			2004			2005			2004			2005			2004			2005			2004			2005			2004			2005			2004			2005			2004			2005			2004
Service cost	$	7,390		$	6,350		$	1,345		$	1,171		$	14,673		$	13,101		$	2,618		$	2,265		$	7,354		$	6,677		$	1,316		$	1,133		$	22,027		$	19,778		$	3,934		$	3,398
Interest cost		13,031			12,721			2,744			2,801			26,089			25,331			5,552			5,385			13,001			12,662			2,759			2,693			39,090			37,993			8,311			8,078
Expected return on plan assets		(18,535	)		(18,254	)		(2,440	)		(2,736	)		(36,909	)		(36,463	)		(4,925	)		(4,845	)		(18,569	)		(18,209	)		(2,465	)		(2,423	)		(55,478	)		(54,672	)		(7,390	)		(7,268	)
Amortization of unrecognized transition obligation		1			1			785			749			2			2			1,569			1,569			1			1			785			785			3			3			2,354			2,354
Amortization of prior service cost (gain)		(165	)		(148	)		(3	)		4			(311	)		(297	)		—			7			(156	)		(145	)		—			3			(467	)		(442	)		—			10
Recognized actuarial loss (gain)		1,402			373			72			(308	)		2,996			592			231			—
Recognized actuarial loss																										1,447			284			101			—			4,443			876			332			—

Net periodic benefit cost	$	3,124		$	1,043		$	2,503		$	1,681		$	6,540		$	2,266		$	5,045		$	4,381		$	3,078		$	1,270		$	2,496		$	2,191		$	9,618		$	3,536		$	7,541		$	6,572

Of the net periodic benefit costs, the Company recorded expense of $9$14 million and $6$9 million in the first ~~six~~nine months of 2005 and 2004, respectively, and charged the remaining amounts primarily to electric utility plant.

On April 20, 2004, the HEI Board of Directors approved a 2-for-1 stock split in the form of a 100% stock dividend with a record date of May 10, 2004 and a distribution date of June 10, 2004. All share and per share information in the accompanying financial statements, notes and elsewhere in this Form 10-Q have been adjusted to reflect the stock split for all periods presented (unless otherwise noted).

In May 2005, HEI and HEI Investments, Inc. (HEIII) entered into an agreement with a third party for the sale of HEIII’s approximate 25% interest in the trust that is the lessor under a lease of a 60% undivided interest in a coal-fired electric generating plant in Georgia, subject to the satisfaction of numerous conditions, including a facility appraisal and board or executive committee approvals. The sale is expected to close prior to the end of the third quarter of 2005. As of July 31, 2005, the carrying value of HEIII’s approximate 25% interest in the trust was $19.5 million and the estimated sales price, net of nonrecourse debt to be assumed by the third party, was approximately $34 million; however, the sales price is subject to adjustment based on the date the transaction is closed and prevailing interest rates at that time. At July 31, 2005, such purchase price adjustment would have been immaterial.

~~Also, see~~See Note 5, “Discontinued operations,” above and Note 5, “Commitments and contingencies,” of HECO’s “Notes to ~~HECO’s~~ Consolidated Financial Statements.”

For the ~~six~~nine months ended ~~June~~September 30, 2005 and 2004, the Company paid interest amounting to ~~$88.4~~$126.8 million and ~~$84.1~~$116.6 million, respectively.

For the ~~six~~nine months ended ~~June~~September 30, 2005 and 2004, the Company paid income taxes amounting to ~~$19.5~~$20.7 million and ~~$2.5~~$5.2 million, respectively. The increase for the first ~~half~~nine months of 2005 compared to the first ~~half~~nine months of 2004 is primarily due to the ~~payment~~payments of previously accrued bank franchise and federal income taxes in settlement of prior years’ liabilities.

Under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP), common stock dividends reinvested by shareholders in HEI common stock in noncash transactions amounted to $4.5 million for the ~~six~~nine months ended ~~June~~September 30, 2004. Beginning in March 2004, HEI began satisfying the requirements of the HEI DRIP and the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) by acquiring for cash its common shares through open market purchases rather than the issuances of additional shares.

Other noncash increases in common stock for director and officer compensatory plans were ~~$4.2~~$4.6 million and ~~$1.9~~$2.4 million for the ~~six~~nine months ended ~~June~~September 30, 2005 and 2004, respectively.

For a discussion of recent accounting pronouncements and interpretations regarding the consolidation of variable interest entities and the tax effects of income from domestic production activities, see Note 7 of HECO’s “Notes to ~~HECO’s~~ Consolidated Financial Statements.”

In March 2004, the Financial Accounting Standards Board (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 ~~(planned to be retitled~~(retitled as FSP FAS ~~115-1)~~115-1 and FAS 124-1). The ~~final~~guidance in FSP ~~will replace~~FAS 115-1 and FAS 124-1 addresses the ~~guidance set forth in paragraphs 10 through 18~~determination of ~~EITF Issue No. 03-1 with references~~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 ~~existing~~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 ~~such as~~in this FSP amends FASB Statement No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” ~~SEC Staff Accounting Bulletin~~and FASB Statement No. ~~59,~~124, “Accounting for ~~Noncurrent Marketable Equity Securities,~~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.

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. Since the Company adopted the recognition provisions of SFAS No. 123 as of January 1, 2002, the only change the Company expects to make upon adoption of SFAS No. 123 (revised 2004) is how it accounts for forfeitures. Historically, forfeitures have not been significant. SFAS No. 123 (revised 2004) is effective as of January 1, 2006 for the Company. Also, 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 will adopt the provisions of SFAS No. 123 (revised 2004) and the guidance in SAB No. 107 on January 1, 2006 and expects the impact of adoption towill be immaterial.

In March 2005, the FASB issued FIN 47, “Accounting for Conditional Asset Retirement Obligations,” which will require 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 must adopt the provisions of FIN 47 no later than December 31, 2005. Management has not yet determined the impact of adoption on the Company’s financial position or results of operations.

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 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 ~~its~~such impact.

In the first quarter of 2005, the Company recorded a $3 million reserve for potential interest on the disputed timing of dividend income recognition. In the second quarter of 2005, the Company made a $30 million deposit primarily to stop the further accrual of interest on the disputed timing of dividend income recognition related to a change in ASB’s 2000 and 2001 tax year-ends. ~~At June~~As of September 30, 2005, $3 million, net of tax effects, was accrued for unresolved tax issues and related interest. In the second quarter of 2005, $1 million of income taxes and interest payable were reversed due to the resolution of audit issues with the Internal Revenue Service. The Company believes it has adequately provided for the issue involving the disputed timing of dividend income recognition and other minor unresolved income tax issues with federal and state tax authorities 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 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.

As of ~~July 1,~~September 30, 2005, HEI Properties, Inc. (HEIPI) ~~had a $0.5 million investment in~~held 666,667 shares of Hoku Scientific, Inc. (Hoku), a Hawaii fuel cell technology startup company. ~~The~~Prior to August 5, 2005, the investment had been accounted for under the cost method since Hoku was a non-controlled corporation, HEIPI did not have the ability to exercise significant influence over the operating and financial policies of Hoku, and Hoku’s shares were not publicly traded. Hoku went public and shares of Hoku began trading on the Nasdaq Stock Market on August 5, 2005 (closing price of ~~$5.36)~~$10.70 on September 30, 2005 and $10.59 on October 31, 2005). HEIPI is subject to certain “lockup” provisions that expire in February 2006. ~~Commencing on~~Since August 5, 2005, ~~the~~ Hoku ~~securities will be~~shares have been considered marketable and HEIPI ~~will classify~~has classified the ~~securities~~shares as trading securities, carried at fair value with changes in fair value recorded in earnings. As of September 30, 2005, HEIPI carried its investment in Hoku shares at $7 million, and in the third quarter of 2005, HEIPI recognized a $4 million unrealized after-tax gain on the Hoku shares.


(in thousands, except par value)	June 30, 2005			December 31, 2004			September 30, 2005			December 31, 2004
Assets
Utility plant, at cost
Land	$	32,988		$	32,995		$	32,988		$	32,995
Plant and equipment		3,650,367			3,573,716			3,689,748			3,573,716
Less accumulated depreciation		(1,410,758	)		(1,361,703	)		(1,435,445	)		(1,361,703	)
Plant acquisition adjustment, net		171			197			158			197
Construction in progress		108,609			102,949			131,138			102,949

Net utility plant		2,381,377			2,348,154			2,418,587			2,348,154

Current assets
Cash and equivalents		2,771			327			2,903			327
Customer accounts receivable, net		104,080			102,007			119,058			102,007
Accrued unbilled revenues, net		80,350			79,028			90,181			79,028
Other accounts receivable, net		3,827			6,499			4,386			6,499
Fuel oil stock, at average cost		64,770			58,570			77,778			58,570
Materials and supplies, at average cost		27,347			23,768			26,889			23,768
Prepaid pension benefit cost		102,289			106,018			100,618			106,018
Other		7,636			8,327			8,270			8,327

Total current assets		393,070			384,544			430,083			384,544

Other long-term assets
Regulatory assets		109,063			108,630			109,518			108,630
Unamortized debt expense		14,829			14,724			14,612			14,724
Other		24,758			23,563			25,945			23,563

Total other long-term assets		148,650			146,917			150,075			146,917

	$	2,923,097		$	2,879,615		$	2,998,745		$	2,879,615

Capitalization and liabilities
Capitalization
Common stock, $6 2/3 par value, authorized 50,000 shares; outstanding 12,806 shares	$	85,387		$	85,387		$	85,387		$	85,387
Premium on capital stock		299,187			298,938			299,186			298,938
Retained earnings		645,586			632,779			653,440			632,779

Common stock equity		1,030,160			1,017,104			1,038,013			1,017,104
Cumulative preferred stock – not subject to mandatory redemption		34,293			34,293			34,293			34,293
Long-term debt, net		760,079			752,735			765,009			752,735

Total capitalization		1,824,532			1,804,132			1,837,315			1,804,132

Current liabilities
Short-term borrowings–nonaffiliates		122,591			76,611			112,426			76,611
Short-term borrowings–affiliate		—			11,957			12,575			11,957
Accounts payable		74,464			94,015			93,045			94,015
Interest and preferred dividends payable		10,261			10,738			14,984			10,738
Taxes accrued		105,816			105,925			116,541			105,925
Other		27,037			34,981			28,316			34,981

Total current liabilities		340,169			334,227			377,887			334,227

Deferred credits and other liabilities
Deferred income taxes		190,652			189,193			207,223			189,193
Regulatory liabilities		208,172			197,089			213,230			197,089
Unamortized tax credits		53,918			53,208			53,995			53,208
Other		69,324			66,261			66,590			66,261

Total deferred credits and other liabilities		522,066			505,751			541,038			505,751

Contributions in aid of construction		236,330			235,505			242,505			235,505

	$	2,923,097		$	2,879,615		$	2,998,745		$	2,879,615

See accompanying “Notes to ~~HECO’s~~ Consolidated Financial ~~Statements.”~~Statements” for HECO.


(in thousands, except for ratio of earnings to fixed charges)	Three months ended June 30,						Six months ended June 30,						Three months ended September 30,						Nine months ended September 30,
	2005			2004			2005			2004			2005			2004			2005			2004
Operating revenues	$	428,807		$	369,393		$	802,497		$	715,337		$	489,877		$	408,766		$	1,292,374		$	1,124,103

Operating expenses
Fuel oil		148,775			114,496			264,401			211,582			182,663			128,584			447,064			340,166
Purchased power		106,369			94,267			207,585			186,506			122,086			105,985			329,671			292,491
Other operation		41,794			36,877			83,110			71,146			41,974			39,151			125,084			110,297
Maintenance		19,837			15,910			37,775			32,906			21,141			17,219			58,916			50,125
Depreciation		30,822			28,744			61,642			57,488			30,655			28,586			92,297			86,074
Taxes, other than income taxes		39,293			34,198			75,264			67,082			44,990			37,588			120,254			104,670
Income taxes		12,293			13,779			20,031			26,666			13,754			16,788			33,785			43,454

		399,183			338,271			749,808			653,376			457,263			373,901			1,207,071			1,027,277

Operating income		29,624			31,122			52,689			61,961			32,614			34,865			85,303			96,826

Other income
Allowance for equity funds used during construction		1,182			1,673			2,269			3,122			1,406			1,934			3,675			5,056
Other, net		777			1,088			1,620			1,729			1,191			1,157			2,811			2,886

		1,959			2,761			3,889			4,851			2,597			3,091			6,486			7,942

Income before interest and other charges		31,583			33,883			56,578			66,812			35,211			37,956			91,789			104,768

Interest and other charges
Interest on long-term debt		10,656			10,825			21,565			20,895			10,731			10,821			32,296			31,716
Amortization of net bond premium and expense		557			577			1,113			1,146			545			578			1,658			1,724
Other interest charges		702			980			1,775			3,392			1,408			743			3,183			4,135
Allowance for borrowed funds used during construction		(475	)		(733	)		(902	)		(1,377	)		(558	)		(859	)		(1,460	)		(2,236	)
Preferred stock dividends of subsidiaries		229			229			458			458			228			228			686			686

		11,669			11,878			24,009			24,514			12,354			11,511			36,363			36,025

Income before preferred stock dividends of HECO		19,914			22,005			32,569			42,298			22,857			26,445			55,426			68,743

Preferred stock dividends of HECO		270			270			540			540			270			270			810			810

Net income for common stock	$	19,644		$	21,735		$	32,029		$	41,758		$	22,587		$	26,175			54,616		$	67,933

Ratio of earnings to fixed charges (SEC method)								3.00			3.53									3.24			3.79


	Three months ended June 30,					Six months ended June 30,
(in thousands)												Three months ended September 30,					Nine months ended September 30,
(in thousands)	2005			2004		2005			2004			2005			2004		2005			2004
Retained earnings, beginning of period	$	635,231		$	571,625	$	632,779		$	563,215		$	645,586		$	593,360	$	632,779		$	563,215
Net income for common stock		19,644			21,735		32,029			41,758			22,587			26,175		54,616			67,933
Common stock dividends		(9,289	)		—		(19,222	)		(11,613	)		(14,733	)		—		(33,955	)		(11,613	)

Retained earnings, end of period	$	645,586		$	593,360	$	645,586		$	593,360		$	653,440		$	619,535	$	653,440		$	619,535

HEI owns all the common stock of HECO. Therefore, per share data with respect to shares of common stock of HECO are not meaningful.

See accompanying “Notes to ~~HECO’s~~ Consolidated Financial ~~Statements.”.~~Statements” for HECO.


Six months ended June 30	2005			2004
(in thousands)							Nine months ended September 30

(in thousands)							2005			2004
(in thousands)
Income before preferred stock dividends of HECO	$	32,569		$	42,298		$	55,426		$	68,743
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities
Depreciation of property, plant and equipment		61,642			57,488			92,297			86,074
Other amortization		4,568			4,448			6,675			6,639
Deferred income taxes		1,336			6,142			17,935			16,619
Tax credits, net		1,385			2,282			1,800			3,790
Allowance for equity funds used during construction		(2,269	)		(3,122	)		(3,675	)		(5,056	)
Changes in assets and liabilities
Decrease (increase) in accounts receivable		599			(2,254	)
Increase in accounts receivable								(14,938	)		(16,017	)
Increase in accrued unbilled revenues		(1,322	)		(3,803	)		(11,153	)		(8,162	)
Increase in fuel oil stock		(6,200	)		(5,303	)		(19,208	)		(14,053	)
Increase in materials and supplies		(3,579	)		(2,571	)		(3,121	)		(2,889	)
Increase in regulatory assets		(1,167	)		(656	)		(2,815	)		(938	)
Decrease in accounts payable		(19,551	)		(3,120	)
Increase (decrease) in taxes accrued		(109	)		1,157
Increase (decrease) in accounts payable								(970	)		13,407
Increase in taxes accrued								10,616			16,585
Changes in other assets and liabilities		(4,788	)		(9,133	)		(3,738	)		(18,210	)

Net cash provided by operating activities		63,114			83,853			125,131			146,532

Cash flows from investing activities
Capital expenditures		(83,516	)		(84,430	)		(142,573	)		(135,051	)
Contributions in aid of construction		5,444			3,448			10,274			5,857
Other		1,423			1,547			1,476			1,951

Net cash used in investing activities		(76,649	)		(79,435	)		(130,823	)		(127,243	)

Cash flows from financing activities
Common stock dividends		(19,222	)		(11,613	)		(33,955	)		(11,613	)
Preferred stock dividends		(540	)		(540	)		(810	)		(810	)
Proceeds from issuance of long-term debt		53,643			52,073			58,525			52,525
Repayment of long-term debt		(47,000	)		(103,092	)		(47,000	)		(103,092	)
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		34,023			71,313			36,433			49,972
Other		(4,925	)		(2,975	)		(4,925	)		301

Net cash provided by financing activities		15,979			5,166
Net cash provided by (used in) financing activities								8,268			(12,717	)

Net increase in cash and equivalents		2,444			9,584			2,576			6,572
Cash and equivalents, beginning of period		327			158			327			158

Cash and equivalents, end of period	$	2,771		$	9,742		$	2,903		$	6,730

See accompanying “Notes to ~~HECO’s~~ Consolidated Financial ~~Statements.”~~Statements” for HECO.

The accompanying unaudited consolidated financial statements have been prepared in conformity with GAAP for interim financial information, the instructions to SEC Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenues and expenses for the period. Actual results could differ significantly from those estimates. The accompanying unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and the notes thereto included in HECO’s SEC Form 10-K for the year ended December 31, 2004 and the unaudited consolidated financial statements and the notes thereto in HECO’s Quarterly ~~Report~~Reports on SEC Form 10-Q for the ~~quarter~~quarters ended March 31, 2005 and June 30, 2005.

In the opinion of HECO’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to present fairly the financial position of HECO and its subsidiaries as of ~~June~~September 30, 2005 and December 31, 2004 and the results of their operations for the three and ~~six~~nine months ended ~~June~~September 30, 2005 and 2004 and their cash flows for the ~~six~~nine months ended ~~June~~September 30, 2005 and 2004. All such adjustments are of a normal recurring nature, unless otherwise disclosed in this Form 10-Q or other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year. When required, certain reclassifications are made to the prior period’s consolidated financial statements to conform to the current presentation. For example, assets and liabilities at December 31, 2004 have been restated for the reclassification of regulatory assets from “Regulatory liabilities, net” to “Regulatory assets.”

(2) ~~HECO-obligated mandatorily redeemable trust preferred securities of unconsolidated subsidiary trusts holding solely~~ Unconsolidated variable interest entities

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 ($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 Maui Electric Company, Limited (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, “Consolidation of Variable Interest Entities.” Trust III’s balance sheet as of ~~June~~September 30, 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 ~~six~~nine months ended ~~June~~September 30, 2005 consisted of ~~$1.7~~$2.5 million of interest income received from the 2004 Debentures; ~~$1.6~~$2.4 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.

In October 1988, HECO ~~Capital Trust I (Trust I) was~~entered into a ~~financing entity,~~power purchase agreement (PPA) with Kalaeloa Partners, L.P. (Kalaeloa), which ~~issued,~~provided that HECO would purchase 180 MW of firm capacity for a period of 25 years beginning in ~~1997, $50 million of 8.05% Cumulative Quarterly Income Preferred Securities, Series 1997 (1997 Trust Preferred Securities) to the public.~~May 1991. In ~~March~~October 2004, HECO ~~HELCO~~ and ~~MECO borrowed~~Kalaeloa entered into amendments, which together effectively increased the ~~proceeds~~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 ~~sale of Trust III’s 2004 Trust Preferred Securities and, in April 2004, applied the proceeds, along with other corporate funds,~~Gross National Product Implicit Price Deflator. The capacity payments that HECO makes 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 until they were deconsolidatedKalaeloa 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 Kalealoa’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 ~~January 1, 2004. Trust I~~the PPA, the PPA does not expose HECO to losses as the fuel and ~~Trust II were dissolved~~fuel related energy payments under the PPA have been approved by the PUC for recovery from customers through base electric rates and ~~terminated~~through HECO’s energy cost adjustment clause to the extent the fuel and fuel related energy payments are not included in ~~2004.~~base energy rates.

HECO and its subsidiaries’ operating revenues include amounts for various revenue taxes. Revenue taxes are generally recorded as an expense in the period the related revenues are recognized. HECO and its subsidiaries’ payments to the taxing authorities are based on the prior year’s revenues. For the ~~six~~nine months ended ~~June~~September 30, 2005 and 2004, HECO and its subsidiaries included approximately ~~$71~~$114 million and ~~$63~~$99 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

In the first ~~six~~nine months of 2005 and 2004, HECO and its subsidiaries paid contributions of $5$8 million and $5$22 million, respectively, to the retirement benefit plans. HECO and its subsidiaries’ current estimate of contributions to the retirement benefit plans in 2005 is $11 million, compared to their contributions of $34 million in 2004.


	Three months ended June 30												Six months ended June 30												Three months ended September 30												Nine months ended September 30
	Pension benefits						Other benefits						Pension benefits						Other benefits						Pension benefits						Other benefits						Pension benefits						Other benefits
(in thousands)	2005			2004			2005			2004			2005			2004			2005			2004			2005			2004			2005			2004			2005			2004			2005			2004
Service cost	$	6,030		$	5,146		$	1,307		$	1,139		$	11,904		$	10,723		$	2,544		$	2,203		$	5,969		$	5,361		$	1,280		$	1,102		$	17,873		$	16,084		$	3,824		$	3,305
Interest cost		11,722			11,503			2,684			2,731			23,438			22,888			5,420			5,251			11,675			11,444			2,694			2,626			35,113			34,332			8,114			7,877
Expected return on plan assets		(16,812	)		(16,708	)		(2,402	)		(2,699	)		(33,462	)		(33,341	)		(4,850	)		(4,777	)		(16,847	)		(16,670	)		(2,428	)		(2,388	)		(50,309	)		(50,011	)		(7,278	)		(7,165	)
Amortization of unrecognized transition obligation		—			—			783			749			1			1			1,565			1,565			1			1			782			782			2			2			2,347			2,347
Amortization of prior service gain		(197	)		(186	)		—			—			(385	)		(372	)		—			—			(192	)		(186	)		—			—			(577	)		(558	)		—			—
Recognized actuarial loss (gain)		1,145			82			59			(295	)		2,402			108			206			—
Recognized actuarial loss																										1,150			54			90			—			3,552			162			296			—

Net periodic benefit cost	$	1,888		$	(163	)	$	2,431		$	1,625		$	3,898		$	7		$	4,885		$	4,242		$	1,756		$	4		$	2,418		$	2,122		$	5,654		$	11		$	7,303		$	6,364

Of the net periodic benefit costs, HECO and its subsidiaries recorded expense of $6$10 million and $3$5 million in the first ~~six~~nine months of 2005 and 2004, respectively, and charged the remaining amounts primarily to electric utility plant.

~~At June~~As of September 30, 2005, HECO and its subsidiaries had recognized ~~$18~~$19 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.

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 steam recovery generator (ST-7), at which time these units would be converted to a 56 MW (net) dual train combined-cycle unit. In January 1994, the PUC approved expenditures for CT-4. 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, which have been described in ~~detail in~~ previous periodic reports filed with the SEC. 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 additional noise mitigation work for CT-5 (not requiring any further construction) is ~~ongoing. Completion of noise mitigation measures is a condition~~ongoing to ensure compliance with the ~~full time operation of the units.~~night-time standard. Currently, HELCO can operate Keahole as required to meet its system needs.

Currently, three 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; and (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. 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. On March 2, 2005, Waimana and another party appealed a judgment upholding the BLNR’s approval of the long-term lease allowing HELCO to use brackish well water, and Waimana has also appealed the denial of its motion seeking relief from judgment in the water lease case. In July 2005, the two appeals relating to the water lease were consolidated by the Hawaii Supreme Court. 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 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).

~~HELCO’s plans for ST-7 are pending until it obtains the contemplated reclassification of~~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 a contemplated County rezoning to a “General Industrial” classification and obtains the necessary permits. HELCO has filed a petition for reclassification with the State Land Use Commission. Evidentiary hearings were held in May 2005 and concluded in July 2005, and the commission stated that HELCO’s petition would be considered in August 2005.

Costs incurred; management’s evaluation. As of ~~June~~September 30, 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 ~~$108~~$109 million, including ~~$42~~$43 million for equipment and material purchases, $46 million for planning, engineering, permitting, site development and other costs and $20 million for an allowance for funds used during construction (AFUDC) up to November 30, 1998, after which date management decided not to continue accruing AFUDC. Of this amount, $103 million has been reclassified from construction in progress to plant and equipment and depreciation has been recorded since January 1, 2005. As of June 30, 2005, estimated additional capital costs of $4 million will be required for the installations of CT-4 and CT-5, including the costs necessary to satisfy the requirements of the Settlement Agreement.

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. While management believes that no adjustment to costs incurred to put CT-4 and CT-5 into service is required as of ~~June~~September 30, 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.

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 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 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 $55 million; see costs incurred below) for a revised ~~East Oahu Transmission Project~~EOTP using the 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 ~~June~~September 30, 2005, the accumulated costs recorded for the ~~East Oahu Transmission Project~~EOTP amounted to $25 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 $10 million for AFUDC. In the written testimony filed in June 2005, the ~~CA’s~~Consumer Advocate’s consultant ~~contends~~contended that HECO should always have planned for a project using only the 46 kV system and ~~recommends~~recommended that HECO be required to expense the $12 million incurred before 2003, and the related AFUDC. ~~HECO plans to vigorously contest the CA’s recommendation in HECO’s~~In rebuttal testimony ~~which is expected~~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 ~~be filed at~~ the ~~end of August 2005.~~transmission concerns the project addressed. The PUC has scheduled an evidentiary hearing on HECO’s application in November 2005. ~~The pre-2003 cost recovery issue, however, may not be decided by~~In November 2005, the PUC ~~until~~approved a stipulation between HECO ~~seeks~~and the Consumer Advocate that this proceeding should determine whether HECO should be given approval to ~~include project costs in its rate base in a future rate-making proceeding after all or~~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 ~~in-service.~~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 ~~June~~September 30, 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.

HECO, HELCO and MECO, like other utilities, periodically identify petroleum or other chemical releases into the environment associated with current operations at their generation plants and other facilities 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 subsidiaries’ releases identified to date will not have a material adverse effect, individually and in the aggregate, on the Company’s or consolidated HECO’s financial statements.

Additionally, current environmental laws may require the 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 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.

~~Management~~In 2001, management developed a preliminary estimate of HECO’s share of costs ~~primarily from 2002 through 2005~~ 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 $0.5 million has been incurred through ~~June~~September 30, 2005). Because (1) the full scope and extent of additional investigative work, remedial activities and monitoring are unknown at this time, (2) the final cost allocation method has not yet been determined and (3) management cannot estimate the costs to be incurred (if any) for the sites other than the Iwilei Unit (including its Honolulu power plant site), the cost estimate may be subject to significant change and additional material investigative and remedial costs may be incurred.

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 HEl

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, Inc. (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 the Company’s or HECO’s consolidated financial position, results of operations or liquidity.

Approximately 60% of the electric utilities’ 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).

For the ~~six~~nine months ended ~~June~~September 30, 2005 and 2004, HECO and its subsidiaries paid interest amounting to ~~$23.1~~$30.0 million and ~~$23.8~~$30.1 million, respectively.

For the ~~six~~nine months ended ~~June~~September 30, 2005 and 2004, HECO and its subsidiaries paid income taxes amounting to ~~$2.9~~$5.3 million and ~~$6.4~~$6.5 million, respectively.

The allowance for equity funds used during construction, which was charged to construction in progress as part of the cost of electric utility plant, amounted to ~~$2.3~~$3.7 million and ~~$3.1~~$5.1 million for the ~~six~~nine months ended ~~June~~September 30, 2005 and 2004, respectively.

In March 2004, HECO, HELCO and MECO issued 6.50% Junior Subordinated Deferrable Interest Debentures to HECO Capital Trust III in the aggregate principal amount of approximately $51.5 million and directed that the proceeds from the issuance of the debentures be deposited with the trustee for HECO Capital Trust I and ultimately be used in April 2004 to redeem ~~its~~HECO Capital Trust I’s 8.05% Cumulative Quarterly Income Preferred Securities ($50 million aggregate liquidation preference) and its common securities of approximately $1.5 million. In March 2004, HECO, HELCO and MECO recorded noncash transactions to reflect the aggregate $51.5 million receivable from HECO Capital Trust I (included in “Other accounts receivable, net”) and the aggregate $51.5 million obligation under the 6.50% Junior Subordinated Deferrable Interest Debentures (included in “Long-term debt, net”). ~~See Note 2 for additional information.~~

For a discussion of recent accounting pronouncements and interpretations regarding other-than-temporary impairment and its application to certain investments, asset retirement obligations and accounting changes and error corrections, see Note 1110 of HEI’s “Notes to ~~HEI’s~~ Consolidated Financial Statements.”

In December 2003, the FASB issued 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 ~~June~~September 30, 2005, HECO and its subsidiaries had six PPAs for a total of ~~512~~540 MW of firm capacity, and other PPAs with smaller IPPs and Schedule Q providers that supplied as-available energy. Approximately 91% of the ~~512~~540 MW of firm capacity is under PPAs, entered into before December 31, 2003, with AES Hawaii, Kalaeloa Partners, L.P. (Kalaeloa), Hamakua Energy Partners, L.P. (Hamakua) and H-POWER. Purchases from all IPPs for the ~~six~~nine months ended ~~June~~September 30, 2005 totaled ~~$208~~$330 million, with purchases from AES Hawaii, Kalaeloa, Hamakua and H-POWER totaling ~~$68~~$102 million, ~~$74~~$121 million, ~~$27~~$44 million and ~~$16~~$24 million, respectively. The primary business activities of these IPPs are the generation and sale of power to HECO and its subsidiaries. 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 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.

HECO and its subsidiaries have reviewed their significant PPAs and determined that the IPPs had no contractual obligation to provide such information. In March 2004, HECO and its subsidiaries 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 request for information. (HECO and its subsidiaries excluded their Schedule Q providers from the scope of FIN 46R because HECO and its subsidiaries’ variable interest in the provider would not be significant to HECO and its subsidiaries and they did not participate significantly in the design of the provider.) Some of the IPPs provided sufficient information for HECO and its subsidiaries to determine that the IPP was not a VIE, or was either a “business” or “governmental organization” (H-POWER) 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 HECO and its subsidiaries to determine the applicability of FIN 46R, and HECO and its subsidiaries have been unable to apply FIN 46R to these IPPs. In January 2005, HECO and its subsidiaries 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.

As required under FIN 46R, HECO and its subsidiaries ~~will continue~~have continued their 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 ~~analyses~~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 ~~if certain conditions are satisfied,~~ Kalaeloa ~~may~~would make ~~an additional 29 MW of firm capacity~~ available to HECO. In May 2005, the PUC issued a decision and order (D&O) approving the amendments and determining that HECO may include the additional costs resulting from the amendments in its revenue requirements for rate making purposes. Subject to the satisfaction of certain conditions, the amendments will become effective, and additional firm capacity of up to 29 MW ~~will be made available,~~of additional firm capacity to HECO, if certain conditions were satisfied. The conditions have been satisfied. The amendments became effective when the costs of the additional capacity and purchased power ~~are recoverable from ratepayers~~were included in HECO’s ~~current rate case proceeding, which~~rates as a result of the Interim D&O. As a result of the completion of the required performance test, the additional firm capacity to be provided by Kalaeloa is ~~expected to occur on the effective date of an interim decision that management currently anticipates may be issued in the fourth quarter of 2005. When the first of these amendments becomes effective,~~28 MW. Kalaeloa ~~has agreed to make available to~~provided HECO the information HECO ~~needs~~needed to ~~(1) determine if~~complete its determination of whether Kalaeloa is a variable interest entity, and, whether HECO ~~must consolidate~~is the primary beneficiary. While it has been determined that Kalaeloa ~~under~~is a variable interest entity, HECO has concluded that it is not the ~~provisions~~primary beneficiary of that entity and accordingly Kalaeloa need not be consolidated in HECO’s consolidated financial statements. See Note 2 for additional information regarding the application of FIN 46R (2) consolidate Kalaeloa, if necessary under FIN 46R, and (3) comply with Section 404 of SOX. The consolidation of Kalaeloa, if required, could have a material effect on HECO’s consolidated financial statements, including the recognition of a significant amount of assets and liabilities, and, if Kalaeloa were operating at a loss and had insufficient equity, the potential recognition of such losses.to Kalaeloa.

In October 2004, HELCO and Apollo Energy Corporation (Apollo) executed a restated and amended PPA which enables Apollo to repower its existing 7 MW facility, and install an additional 13.5 MW of capacity, for a total windfarm capacity of 20.5 MW. In December 2004, MECO executed a new PPA with Kaheawa Wind Power, LLC (KWP), which plans to install 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 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 for the consolidation of Apollo and/or KWP, if necessary, would not be material. However, depending on the magnitude of the improvements contemplated in the ~~respective~~ PPAs, the impact of a required consolidation of Apollo and KWP could be material in the future.

See Note 2 for additional information regarding the application of FIN 46R to HECO Capital Trust III.

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 ~~notable~~ provisions with potential implications for HECO and its subsidiaries:

~~Pending further guidance from the Department of Treasury and the Internal Revenue Service on these provisions, management~~Management has not yet determined the impact of these provisions on HECO’s consolidated results of operations, financial condition or liquidity. However, based on current estimates, management expects that the ~~second provision currently~~provisions would not have a significant impact on HECO and its subsidiaries.

HECO and its subsidiaries believe they have adequately provided for income tax issues not yet resolved with federal and state tax authorities. At ~~June~~September 30, 2005, ~~$0.3~~$0.4 million, net of tax effects, was accrued for these issues, which are primarily comprised of asset recovery period classification issues. Although not probable, adverse developments on certain issues could result in additional charges to net income in the future. Based on information currently available, HECO and its subsidiaries believe the ultimate resolution of tax issues for all open tax periods will not have a material adverse effect on HECO’s consolidated results of operations, financial condition or liquidity.

(9) Reconciliation of electric utility operating income per HEI and HECO consolidated statements of income


	Three months ended June 30,						Six months ended June 30,						Three months ended September 30,						Nine months ended September 30,
(in thousands)	2005			2004			2005			2004			2005			2004			2005			2004
Operating income from regulated and nonregulated activities before income taxes (per HEI consolidated statements of income)	$	42,647		$	45,914		$	74,253		$	90,054		$	47,533		$	52,713		$	121,786		$	142,767
Deduct:
Income taxes on regulated activities		(12,293	)		(13,779	)		(20,031	)		(26,666	)		(13,754	)		(16,788	)		(33,785	)		(43,454	)
Revenues from nonregulated activities		(923	)		(1,212	)		(2,008	)		(1,881	)		(1,462	)		(1,310	)		(3,470	)		(3,191	)
Add: Expenses from nonregulated activities		193			199			475			454			297			250			772			704

Operating income from regulated activities after income taxes (per HECO consolidated statements of income)	$	29,624		$	31,122		$	52,689		$	61,961		$	32,614		$	34,865		$	85,303		$	96,826

HECO is not required to provide separate financial statements and other disclosures concerning HELCO and MECO to holders of the 2004 Debentures issued by HELCO and MECO to Trust III since all of their voting capital stock is owned, and these securities have been fully and unconditionally guaranteed, on a subordinated basis, by HECO. Consolidating information is provided below for these and other HECO subsidiaries for the periods ended and as of the dates indicated. HECO also unconditionally guarantees HELCO’s and MECO’s obligations (a) to the State of Hawaii for the repayment of principal and interest on their Special Purpose Revenue Bonds and (b) relating to the trust preferred securities of Trust III. Also, see Note 2. HECO is also obligated to make dividend, redemption and liquidation payments on HELCO’s and MECO’s preferred stock if the respective subsidiary is unable to make such payments.


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and eliminations		HECO consolidated			HECO			HELCO		MECO		RHI	Reclassi-fications and elimina- tions		HECO consoli- dated
Assets
Utility plant, at cost
Land	$	25,652		3,019		4,317		—		—		$	32,988		$	25,652		3,019		4,317		—	—		$	32,988
Plant and equipment		2,257,759		731,166		661,442		—		—			3,650,367			2,276,683		746,621		666,444		—	—			3,689,748
Less accumulated depreciation		(875,500	)	(264,230	)	(271,028	)	—		—			(1,410,758	)		(887,433	)	(270,929	)	(277,083	)	—	—			(1,435,445	)
Plant acquisition adjustment, net		—		—		171		—		—			171			—		—		158		—	—			158
Construction in progress		73,500		20,318		14,791		—		—			108,609			94,008		17,346		19,784		—	—			131,138

Net utility plant		1,481,411		490,273		409,693		—		—			2,381,377			1,508,910		496,057		413,620		—	—			2,418,587

Investment in subsidiaries, at equity		382,302		—		—		—		(382,302	)		—			385,287		—		—		—	(385,287	)		—

Current assets
Cash and equivalents		533		561		1,459		218		—			2,771			466		888		1,389		160	—			2,903
Advances to affiliates		41,500		—		10,750		—		(52,250	)		—			41,200		—		11,000		—	(52,200	)		—
Customer accounts receivable, net		67,781		18,591		17,708		—		—			104,080			77,376		22,317		19,365		—	—			119,058
Accrued unbilled revenues, net		56,429		12,500		11,421		—		—			80,350			64,678		13,857		11,646		—	—			90,181
Other accounts receivable, net		3,043		1,001		304		—		(521	)		3,827			4,251		543		460		—	(868	)		4,386
Fuel oil stock, at average cost		44,528		7,452		12,790		—		—			64,770			54,430		7,283		16,065		—	—			77,778
Materials and supplies, at average cost		14,298		3,083		9,966		—		—			27,347			13,766		3,491		9,632		—	—			26,889
Prepaid pension benefit cost		78,791		15,193		8,305		—		—			102,289			77,644		15,105		7,869		—	—			100,618
Other		7,031		452		153		—		—			7,636			7,704		332		234		—	—			8,270

Total current assets		313,934		58,833		72,856		218		(52,771	)		393,070			341,515		63,816		77,660		160	(53,068	)		430,083

Other long-term assets
Regulatory assets		80,441		15,078		13,544		—		—			109,063			80,801		14,826		13,891		—	—			109,518
Unamortized debt expense		10,084		2,443		2,302		—		—			14,829			9,934		2,414		2,264		—	—			14,612
Other		17,043		4,655		3,060		—		—			24,758			18,057		4,408		3,480		—	—			25,945

Total other long-term assets		107,568		22,176		18,906		—		—			148,650			108,792		21,648		19,635		—	—			150,075

	$	2,285,215		571,282		501,455		218		(435,073	)	$	2,923,097		$	2,344,504		581,521		510,915		160	(438,355	)	$	2,998,745

Capitalization and liabilities
Capitalization
Common stock equity	$	1,030,160		189,524		192,580		198		(382,302	)	$	1,030,160		$	1,038,013		190,694		194,445		148	(385,287	)	$	1,038,013
Cumulative preferred stock–not subject to mandatory redemption		22,293		7,000		5,000		—		—			34,293			22,293		7,000		5,000		—	—			34,293
Long-term debt, net		475,260		130,991		153,828		—		—			760,079			480,169		131,000		153,840		—	—			765,009
									��
Total capitalization		1,527,713		327,515		351,408		198		(382,302	)		1,824,532			1,540,475		328,694		353,285		148	(385,287	)		1,837,315

Current liabilities
Short-term borrowings–nonaffiliates		122,591		—		—		—		—			122,591			112,426		—		—		—	—			112,426
Short-term borrowings–affiliate		10,750		41,500		—		—		(52,250	)		—			23,575		41,200		—		—	(52,200	)		12,575
Accounts payable		50,970		14,921		8,573		—		—			74,464			64,052		18,504		10,489		—	—			93,045
Interest and preferred dividends payable		7,698		1,178		1,516		—		(131	)		10,261			10,362		1,892		2,898		—	(168	)		14,984
Taxes accrued		62,754		18,871		24,191		—		—			105,816			68,716		22,751		25,074		—	—			116,541
Other		17,713		3,478		6,216		20		(390	)		27,037			20,216		2,700		6,088		12	(700	)		28,316

Total current liabilities		272,476		79,948		40,496		20		(52,771	)		340,169			299,347		87,047		44,549		12	(53,068	)		377,887

Deferred credits and other liabilities
Deferred income taxes		145,994		24,816		19,842		—		—			190,652			158,799		25,856		22,568		—	—			207,223
Regulatory liabilities		139,992		39,654		28,526		—		—			208,172			144,233		39,892		29,105		—	—			213,230
Unamortized tax credits		30,914		11,488		11,516		—		—			53,918			30,812		11,760		11,423		—	—			53,995
Other		24,166		31,565		13,593		—		—			69,324			22,744		32,194		11,652		— ��	—			66,590

Total deferred credits and other liabilities		341,066		107,523		73,477		—		—			522,066			356,588		109,702		74,748		—	—			541,038

Contributions in aid of construction		143,960		56,296		36,074		—		—			236,330			148,094		56,078		38,333		—	—			242,505

	$	2,285,215		571,282		501,455		218		(435,073	)	$	2,923,097		$	2,344,504		581,521		510,915		160	(438,355	)	$	2,998,745


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and eliminations		HECO consolidated			HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Operating revenues	$	287,073		68,484		73,250		—		—		$	428,807		$	330,922		79,511		79,444		—		—		$	489,877

Operating expenses
Fuel oil		98,955		13,678		36,142		—		—			148,775			124,427		16,799		41,437		—		—			182,663
Purchased power		79,375		23,313		3,681		—		—			106,369			89,021		29,015		4,050		—		—			122,086
Other operation		28,488		6,055		7,251		—		—			41,794			28,809		6,454		6,711		—		—			41,974
Maintenance		13,225		3,508		3,104		—		—			19,837			14,157		4,250		2,734		—		—			21,141
Depreciation		17,747		6,805		6,270		—		—			30,822			17,583		6,804		6,268		—		—			30,655
Taxes, other than income taxes		26,291		6,322		6,680		—		—			39,293			30,411		7,252		7,327		—		—			44,990
Income taxes		6,674		2,594		3,025		—		—			12,293			7,962		2,413		3,379		—		—			13,754

		270,755		62,275		66,153		—		—			399,183			312,370		72,987		71,906		—		—			457,263

Operating income		16,318		6,209		7,097		—		—			29,624			18,552		6,524		7,538		—		—			32,614

Other income
Allowance for equity funds used during construction		929		69		184		—		—			1,182			1,051		95		260		—		—			1,406
Equity in earnings of subsidiaries		8,997		—		—		—		(8,997	)		—			9,768		—		—		—		(9,768	)		—
Other, net		977		89		135		(50	)	(374	)		777			1,436		103		192		(50	)	(490	)		1,191

		10,903		158		319		(50	)	(9,371	)		1,959			12,255		198		452		(50	)	(10,258	)		2,597

Income (loss) before interest and other charges		27,221		6,367		7,416		(50	)	(9,371	)		31,583			30,807		6,722		7,990		(50	)	(10,258	)		35,211

Interest and other charges
Interest on long-term debt		6,621		1,808		2,227		—		—			10,656			6,695		1,809		2,227		—		—			10,731
Amortization of net bond premium and expense		350		102		105		—		—			557			343		98		104		—		—			545
Other interest charges		705		249		122		—		(374	)		702			1,319		475		104		—		(490	)		1,408
Allowance for borrowed funds used during construction		(369	)	(26	)	(80	)	—		—			(475	)		(407	)	(38	)	(113	)	—		—			(558	)
Preferred stock dividends of subsidiaries		—		—		—		—		229			229			—		—		—		—		228			228

		7,307		2,133		2,374		—		(145	)		11,669			7,950		2,344		2,322		—		(262	)		12,354

Income (loss) before preferred stock dividends of HECO		19,914		4,234		5,042		(50	)	(9,226	)		19,914			22,857		4,378		5,668		(50	)	(9,996	)		22,857
Preferred stock dividends of HECO		270		133		96		—		(229	)		270			270		133		95		—		(228	)		270

Net income (loss) for common stock	$	19,644		4,101		4,946		(50	)	(8,997	)	$	19,644		$	22,587		4,245		5,573		(50	)	(9,768	)	$	22,587


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and eliminations		HECO consolidated			HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Retained earnings, beginning of period	$	635,231		86,565		95,756		(233	)	(182,088	)	$	635,231		$	645,586		88,881		97,659		(283	)	(186,257	)	$	645,586
Net income (loss) for common stock		19,644		4,101		4,946		(50	)	(8,997	)		19,644			22,587		4,245		5,573		(50	)	(9,768	)		22,587
Common stock dividends		(9,289	)	(1,785	)	(3,043	)	—		4,828			(9,289	)		(14,733	)	(3,074	)	(3,710	)	—		6,784			(14,733	)

Retained earnings, end of period	$	645,586		88,881		97,659		(283	)	(186,257	)	$	645,586		$	653,440		90,052		99,522		(333	)	(189,241	)	$	653,440


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated			HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Operating revenues	$	250,857		57,349		61,187		—		—		$	369,393		$	276,476		63,783		68,507		—		—		$	408,766

Operating expenses
Fuel oil		80,165		8,516		25,815		—		—			114,496			87,062		10,420		31,102		—		—			128,584
Purchased power		69,106		22,125		3,036		—		—			94,267			78,874		23,838		3,273		—		—			105,985
Other operation		24,957		5,722		6,198		—		—			36,877			25,568		6,791		6,792		—		—			39,151
Maintenance		10,090		2,842		2,978		—		—			15,910			10,969		2,854		3,396		—		—			17,219
Depreciation		17,381		5,291		6,072		—		—			28,744			17,223		5,291		6,072		—		—			28,586
Taxes, other than income taxes		23,230		5,320		5,648		—		—			34,198			25,356		5,833		6,399		—		—			37,588
Income taxes		8,137		2,123		3,519		—		—			13,779			10,520		2,750		3,518		—		—			16,788

		233,066		51,939		53,266		—		—			338,271			255,572		57,777		60,552		—		—			373,901

Operating income		17,791		5,410		7,921		—		—			31,122			20,904		6,006		7,955		—		—			34,865

Other income
Allowance for equity funds used during construction		1,492		71		110		—		—			1,673			1,716		90		128		—		—			1,934
Equity in earnings of subsidiaries		8,880		—		—		—		(8,880	)		—			9,510		—		—		—		(9,510	)		—
Other, net		1,058		92		46		(9	)	(99	)		1,088			1,260		30		51		(10	)	(174	)		1,157

		11,430		163		156		(9	)	(8,979	)		2,761			12,486		120		179		(10	)	(9,684	)		3,091

Income (loss) before interest and other charges		29,221		5,573		8,077		(9	)	(8,979	)		33,883
Income before interest and other charges																33,390		6,126		8,134		(10	)	(9,684	)		37,956

Interest and other charges
Interest on long-term debt		6,746		1,855		2,224		—		—			10,825			6,754		1,831		2,236		—		—			10,821
Amortization of net bond premium and expense		370		100		107		—		—			577			372		101		105		—		—			578
Other interest charges		756		189		134		—		(99	)		980			585		241		91		—		(174	)		743
Allowance for borrowed funds used during construction		(656	)	(34	)	(43	)	—		—			(733	)		(766	)	(44	)	(49	)	—		—			(859	)
Preferred stock dividends of subsidiaries		—		—		—		—		229			229			—		—		—		—		228			228

		7,216		2,110		2,422		—		130			11,878			6,945		2,129		2,383		—		54			11,511

Income (loss) before preferred stock dividends of HECO		22,005		3,463		5,655		(9	)	(9,109	)		22,005
Income before preferred stock dividends of HECO																26,445		3,997		5,751		(10	)	(9,738	)		26,445
Preferred stock dividends of HECO		270		133		96		—		(229	)		270			270		133		95		—		(228	)		270

Net income (loss) for common stock	$	21,735		3,330		5,559		(9	)	(8,880	)	$	21,735
Net income for common stock															$	26,175		3,864		5,656		(10	)	(9,510	)	$	26,175


(in thousands)	HECO		HELCO	MECO	RHI		Reclassi- fications and elimina- tions		HECO consoli- dated		HECO		HELCO	MECO	RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Retained earnings, beginning of period	$	571,625	76,434	93,250	(151	)	(169,533	)	$	571,625	$	593,360	79,763	98,809	(160	)	(178,412	)	$	593,360
Net income (loss) for common stock		21,735	3,330	5,559	(9	)	(8,880	)		21,735
Net income for common stock												26,175	3,864	5,656	(10	)	(9,510	)		26,175
Common stock dividends		—	—	—	—		—			—		—	—	—	—		—			—

Retained earnings, end of period	$	593,360	79,764	98,809	(160	)	(178,413	)	$	593,360	$	619,535	83,627	104,465	(170	)	(187,922	)	$	619,535


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated			HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Operating revenues	$	533,201		132,349		136,947		—		—		$	802,497		$	864,123		211,860		216,391		—		—		$	1,292,374

Operating expenses
Fuel oil		169,839		28,985		65,577		—		—			264,401			294,266		45,784		107,014		—		—			447,064
Purchased power		157,601		43,095		6,889		—		—			207,585			246,622		72,110		10,939		—		—			329,671
Other operation		56,183		12,598		14,329		—		—			83,110			84,992		19,052		21,040		—		—			125,084
Maintenance		25,097		6,741		5,937		—		—			37,775			39,254		10,991		8,671		—		—			58,916
Depreciation		35,493		13,609		12,540		—		—			61,642			53,076		20,413		18,808		—		—			92,297
Taxes, other than income taxes		50,119		12,374		12,771		—		—			75,264			80,530		19,626		20,098		—		—			120,254
Income taxes		10,406		4,107		5,518		—		—			20,031			18,368		6,520		8,897		—		—			33,785

		504,738		121,509		123,561		—		—			749,808			817,108		194,496		195,467		—		—			1,207,071

Operating income		28,463		10,840		13,386		—		—			52,689			47,015		17,364		20,924		—		—			85,303

Other income
Allowance for equity funds used during construction		1,840		102		327		—		—			2,269			2,891		197		587		—		—			3,675
Equity in earnings of subsidiaries		15,390		—		—		—		(15,390	)		—			25,158		—		—		—		(25,158	)		—
Other, net		2,010		148		201		(96	)	(643	)		1,620			3,446		251		393		(146	)	(1,133	)		2,811

		19,240		250		528		(96	)	(16,033	)		3,889			31,495		448		980		(146	)	(26,291	)		6,486

Income (loss) before interest and other charges		47,703		11,090		13,914		(96	)	(16,033	)		56,578			78,510		17,812		21,904		(146	)	(26,291	)		91,789

Interest and other charges
Interest on long-term debt		13,451		3,647		4,467		—		—			21,565			20,146		5,456		6,694		—		—			32,296
Amortization of net bond premium and expense		698		203		212		—		—			1,113			1,041		301		316		—		—			1,658
Other interest charges		1,708		529		181		—		(643	)		1,775			3,027		1,004		285		—		(1,133	)		3,183
Allowance for borrowed funds used during construction		(723	)	(37	)	(142	)	—		—			(902	)		(1,130	)	(75	)	(255	)	—		—			(1,460	)
Preferred stock dividends of subsidiaries		—		—		—		—		458			458			—		—		—		—		686			686

		15,134		4,342		4,718		—		(185	)		24,009			23,084		6,686		7,040		—		(447	)		36,363

Income (loss) before preferred stock dividends of HECO		32,569		6,748		9,196		(96	)	(15,848	)		32,569			55,426		11,126		14,864		(146	)	(25,844	)		55,426
Preferred stock dividends of HECO		540		267		191		—		(458	)		540			810		400		286		—		(686	)		810

Net income (loss) for common stock	$	32,029		6,481		9,005		(96	)	(15,390	)	$	32,029		$	54,616		10,726		14,578		(146	)	(25,158	)	$	54,616


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated			HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Retained earnings, beginning of period	$	632,779		85,861		94,492		(187	)	(180,166	)	$	632,779		$	632,779		85,861		94,492		(187	)	(180,166	)	$	632,779
Net income (loss) for common stock		32,029		6,481		9,005		(96	)	(15,390	)		32,029			54,616		10,726		14,578		(146	)	(25,158	)		54,616
Common stock dividends		(19,222	)	(3,461	)	(5,838	)	—		9,299			(19,222	)		(33,955	)	(6,535	)	(9,548	)	—		16,083			(33,955	)

Retained earnings, end of period	$	645,586		88,881		97,659		(283	)	(186,257	)	$	645,586		$	653,440		90,052		99,522		(333	)	(189,241	)	$	653,440


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated			HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Operating revenues	$	488,235		111,403		115,699		—		—		$	715,337		$	764,711		175,186		184,206		—		—		$	1,124,103

Operating expenses
Fuel oil		148,661		16,018		46,903		—		—			211,582			235,723		26,438		78,005		—		—			340,166
Purchased power		138,858		42,383		5,265		—		—			186,506			217,732		66,221		8,538		—		—			292,491
Other operation		48,159		10,771		12,216		—		—			71,146			73,727		17,562		19,008		—		—			110,297
Maintenance		19,616		6,703		6,587		—		—			32,906			30,585		9,557		9,983		—		—			50,125
Depreciation		34,761		10,582		12,145		—		—			57,488			51,984		15,873		18,217		—		—			86,074
Taxes, other than income taxes		45,761		10,490		10,831		—		—			67,082			71,117		16,323		17,230		—		—			104,670
Income taxes		16,186		3,976		6,504		—		—			26,666			26,706		6,726		10,022		—		—			43,454

		452,002		100,923		100,451		—		—			653,376			707,574		158,700		161,003		—		—			1,027,277

Operating income		36,233		10,480		15,248		—		—			61,961			57,137		16,486		23,203		—		—			96,826

Other income
Allowance for equity funds used during construction		2,784		132		206		—		—			3,122			4,500		222		334		—		—			5,056
Equity in earnings of subsidiaries		16,292		—		—		—		(16,292	)		—			25,802		—		—		—		(25,802	)		—
Other, net		1,898		166		(123	)	(26	)	(186	)		1,729			3,158		196		(72	)	(36	)	(360	)		2,886

		20,974		298		83		(26	)	(16,478	)		4,851			33,460		418		262		(36	)	(26,162	)		7,942

Income (loss) before interest and other charges		57,207		10,778		15,331		(26	)	(16,478	)		66,812
Income before interest and other charges																90,597		16,904		23,465		(36	)	(26,162	)		104,768

Interest and other charges
Interest on long-term debt		13,051		3,523		4,321		—		—			20,895			19,805		5,354		6,557		—		—			31,716
Amortization of net bond premium and expense		734		200		212		—		—			1,146			1,106		301		317		—		—			1,724
Other interest charges		2,357		649		572		—		(186	)		3,392			2,942		890		663		—		(360	)		4,135
Allowance for borrowed funds used during construction		(1,233	)	(65	)	(79	)	—		—			(1,377	)		(1,999	)	(109	)	(128	)	—		—			(2,236	)
Preferred stock dividends of subsidiaries		—		—		—		—		458			458			—		—		—		—		686			686

		14,909		4,307		5,026		—		272			24,514			21,854		6,436		7,409		—		326			36,025

Income (loss) before preferred stock dividends of HECO		42,298		6,471		10,305		(26	)	(16,750	)		42,298
Income before preferred stock dividends of HECO																68,743		10,468		16,056		(36	)	(26,488	)		68,743
Preferred stock dividends of HECO		540		267		191		—		(458	)		540			810		400		286		—		(686	)		810

Net income (loss) for common stock	$	41,758		6,204		10,114		(26	)	(16,292	)	$	41,758
Net income for common stock															$	67,933		10,068		15,770		(36	)	(25,802	)	$	67,933


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated			HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Retained earnings, beginning of period	$	563,215		74,629		92,909		(134	)	(167,404	)	$	563,215		$	563,215		74,629		92,909		(134	)	(167,404	)	$	563,215
Net income (loss) for common stock		41,758		6,204		10,114		(26	)	(16,292	)		41,758
Net income for common stock																67,933		10,068		15,770		(36	)	(25,802	)		67,933
Common stock dividends		(11,613	)	(1,070	)	(4,214	)	—		5,284			(11,613	)		(11,613	)	(1,070	)	(4,214	)	—		5,284			(11,613	)

Retained earnings, end of period	$	593,360		79,763		98,809		(160	)	(178,412	)	$	593,360		$	619,535		83,627		104,465		(170	)	(187,922	)	$	619,535


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated			HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Cash flows from operating activities
Income (loss) before preferred stock dividends of HECO	$	32,569		6,748		9,196		(96	)	(15,848	)	$	32,569		$	55,426		11,126		14,864		(146	)	(25,844	)	$	55,426
Adjustments to reconcile income (loss) before preferred stock dividends of HECO to net cash provided by (used in) operating activities
Equity in earnings		(15,440	)	—		—		—		15,390			(50	)		(25,233	)	—		—		—		25,158			(75	)
Common stock dividends received from subsidiaries		9,349		—		—		—		(9,299	)		50			16,158		—		—		—		(16,083	)		75
Depreciation of property, plant and equipment		35,493		13,609		12,540		—		—			61,642			53,076		20,413		18,808		—		—			92,297
Other amortization		2,173		523		1,872		—		—			4,568			3,404		713		2,558		—		—			6,675
Deferred income taxes		(976	)	1,226		1,086		—		—			1,336			11,829		2,266		3,840		—		—			17,935
Tax credits, net		975		282		128		—		—			1,385			1,100		604		96		—		—			1,800
Allowance for equity funds used during construction		(1,840	)	(102	)	(327	)	—		—			(2,269	)		(2,891	)	(197	)	(587	)	—		—			(3,675	)
Changes in assets and liabilities
Decrease (increase) in accounts receivable		993		(390	)	(939	)	—		935			599
Decrease (increase) in accrued unbilled revenues		(842	)	398		(878	)	—		—			(1,322	)
Increase in accounts receivable																(9,810	)	(3,658	)	(2,752	)	—		1,282			(14,938	)
Increase in accrued unbilled revenues																(9,091	)	(959	)	(1,103	)	—		—			(11,153	)
Decrease (increase) in fuel oil stock		(5,108	)	353		(1,445	)	—		—			(6,200	)		(15,010	)	522		(4,720	)	—		—			(19,208	)
Increase in materials and supplies		(2,758	)	(353	)	(468	)	—		—			(3,579	)		(2,226	)	(761	)	(134	)	—		—			(3,121	)
Decrease (increase) in regulatory assets		(457	)	372		(1,082	)	—		—			(1,167	)		(1,270	)	459		(2,004	)	—		—			(2,815	)
Decrease in accounts payable		(15,612	)	(2,609	)	(1,330	)	—		—			(19,551	)
Increase (decrease) in taxes accrued		(2,212	)	570		1,533		—		—			(109	)
Increase (decrease) in accounts payable																(2,530	)	974		586		—		—			(970	)
Increase in taxes accrued																3,750		4,450		2,416		—		—			10,616
Changes in other assets and liabilities		(5,143	)	(350	)	1,624		16		(935	)		(4,788	)		(3,506	)	354		688		8		(1,282	)		(3,738	)

Net cash provided by (used in) operating activities		31,164		20,277		21,510		(80	)	(9,757	)		63,114			73,176		36,306		32,556		(138	)	(16,769	)		125,131

Cash flows from investing activities
Capital expenditures		(47,481	)	(24,224	)	(11,811	)	—		—			(83,516	)		(84,606	)	(36,693	)	(21,274	)	—		—			(142,573	)
Contributions in aid of construction		3,036		1,636		772		—		—			5,444			5,191		1,909		3,174		—		—			10,274
Advances to affiliates		(6,650	)	—		(3,000	)	—		9,650			—			(6,350	)	—		(3,250	)	—		9,600			—
Other		1,423		—		—		—		—			1,423			1,476		—		—		—		—			1,476

Net cash used in investing activities		(49,672	)	(22,588	)	(14,039	)	—		9,650			(76,649	)		(84,289	)	(34,784	)	(21,350	)	—		9,600			(130,823	)

Cash flows from financing activities
Common stock dividends		(19,222	)	(3,461	)	(5,838	)	—		9,299			(19,222	)		(33,955	)	(6,535	)	(9,548	)	—		16,083			(33,955	)
Preferred stock dividends		(540	)	(267	)	(191	)	—		458			(540	)		(810	)	(400	)	(286	)	—		686			(810	)
Proceeds from issuance of long-term debt		46,643		5,000		2,000		—		—			53,643			51,525		5,000		2,000		—		—			58,525
Repayment of long-term debt		(40,000	)	(5,000	)	(2,000	)	—		—			(47,000	)		(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		37,023		6,650		—		—		(9,650	)		34,023			39,683		6,350		—		—		(9,600	)		36,433
Other		(4,872	)	(53	)	—		—		—			(4,925	)		(4,873	)	(52	)	—		—		—			(4,925	)

Net cash provided by (used in) financing activities		19,032		2,869		(6,029	)	—		107			15,979			11,570		(637	)	(9,834	)	—		7,169			8,268

Net increase (decrease) in cash and equivalents		524		558		1,442		(80	)	—			2,444			457		885		1,372		(138	)	—			2,576
Cash and equivalents, beginning of period		9		3		17		298		—			327			9		3		17		298		—			327

Cash and equivalents, end of period	$	533		561		1,459		218		—		$	2,771		$	466		888		1,389		160		—		$	2,903


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and eliminations		HECO consolidated			HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Cash flows from operating activities
Income (loss) before preferred stock dividends of HECO	$	42,298		6,471		10,305		(26	)	(16,750	)	$	42,298
Adjustments to reconcile income (loss) before preferred stock dividends of HECO to net cash provided by operating activities
Income before preferred stock dividends of HECO															$	68,743		10,468		16,056		(36	)	(26,488	)	$	68,743
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities
Equity in earnings		(16,427	)	—		—		—		16,292			(135	)		(25,962	)	—		—		—		25,802			(160	)
Common stock dividends received from subsidiaries		5,419		—		—		—		(5,284	)		135			5,444		—		—		—		(5,284	)		160
Depreciation of property, plant and equipment		34,761		10,582		12,145		—		—			57,488			51,984		15,873		18,217		—		—			86,074
Other amortization		2,308		389		1,751		—		—			4,448			3,304		581		2,754		—		—			6,639
Deferred income taxes		3,725		2,689		(272	)	—		—			6,142			9,172		2,563		4,884		—		—			16,619
Tax credits, net		981		1,254		47		—		—			2,282			1,652		2,062		76		—		—			3,790
Allowance for equity funds used during construction		(2,784	)	(132	)	(206	)	—		—			(3,122	)		(4,500	)	(222	)	(334	)	—		—			(5,056	)
Changes in assets and liabilities
Decrease (increase) in accounts receivable		259		636		(2,348	)	—		(801	)		(2,254	)
Increase in accounts receivable																(10,887	)	(1,828	)	(3,155	)	—		(147	)		(16,017	)
Increase in accrued unbilled revenues		(1,958	)	(248	)	(1,597	)	—		—			(3,803	)		(6,605	)	(303	)	(1,254	)	—		—			(8,162	)
Increase in fuel oil stock		(2,338	)	(250	)	(2,715	)	—		—			(5,303	)		(11,186	)	(976	)	(1,891	)	—		—			(14,053	)
Increase in materials and supplies		(1,412	)	(186	)	(973	)	—		—			(2,571	)		(1,302	)	(400	)	(1,187	)	—		—			(2,889	)
Decrease (increase) in regulatory assets		241		291		(1,188	)	—		—			(656	)		210		587		(1,735	)	—		—			(938	)
Increase (decrease) in accounts payable		1,915		160		(5,195	)	—		—			(3,120	)		15,262		3,181		(5,036	)	—		—			13,407
Increase (decrease) in taxes accrued		(1,269	)	(1,971	)	4,397		—		—			1,157
Increase in taxes accrued																11,274		1,518		3,793		—		—			16,585
Changes in other assets and liabilities		(7,899	)	(488	)	(1,542	)	(5	)	801			(9,133	)		(14,928	)	(2,071	)	(1,355	)	(3	)	147			(18,210	)

Net cash provided by (used in) operating activities		57,820		19,197		12,609		(31	)	(5,742	)		83,853			91,675		31,033		29,833		(39	)	(5,970	)		146,532

Cash flows from investing activities
Capital expenditures		(54,381	)	(22,230	)	(7,819	)	—		—			(84,430	)		(86,376	)	(34,923	)	(13,752	)	—		—			(135,051	)
Contributions in aid of construction		2,213		624		611		—		—			3,448			3,194		1,476		1,187		—		—			5,857
Proceeds from sale of property																404		—		—		—		—			404
Investment in subsidiary		(1,846	)	—		—		—		300			(1,546	)		(1,846	)	—		—		—		300			(1,546	)
Distributions from unconsolidated subsidiaries		3,093		—		—		—		—			3,093			3,093		—		—		—		—			3,093
Advances from (advances to) affiliates		(16,200	)	—		12,300		—		3,900			—			(17,200	)	—		1,500		—		15,700			—

Net cash provided by (used in) investing activities		(67,121	)	(21,606	)	5,092		—		4,200			(79,435	)		(98,731	)	(33,447	)	(11,065	)	—		16,000			(127,243	)

Cash flows from financing activities
Common stock dividends		(11,613	)	(1,070	)	(4,214	)	—		5,284			(11,613	)		(11,613	)	(1,070	)	(4,214	)	—		5,284			(11,613	)
Preferred stock dividends		(540	)	(267	)	(191	)	—		458			(540	)		(810	)	(400	)	(286	)	—		686			(810	)
Preferred securities distributions of trust subsidiaries		—		—		—		—		—			—
Proceeds from issuance of long-term debt		32,073		10,000		10,000		—		—			52,073			32,525		10,000		10,000		—		—			52,525
Repayment of long-term debt		(63,092	)	(20,000	)	(20,000	)	—		—			(103,092	)		(63,092	)	(20,000	)	(20,000	)	—		—			(103,092	)
Proceeds from issuance of common stock		—		—		—		300		(300	)		—			—		—		—		300		(300	)		—
Net increase in short-term borrowings from affiliate with original maturities of three months or less		59,013		16,200		—		—		(3,900	)		71,313			48,472		17,200		—		—		(15,700	)		49,972
Other		(1,702	)	(1,281	)	8		—		—			(2,975	)		1,573		(1,280	)	8		—		—			301

Net cash provided by (used in) financing activities		14,139		3,582		(14,397	)	300		1,542			5,166			7,055		4,450		(14,492	)	300		(10,030	)		(12,717	)

Net increase in cash and equivalents		4,838		1,173		3,304		269		—			9,584
Net increase (decrease) in cash and equivalents																(1	)	2,036		4,276		261		—			6,572
Cash and equivalents, beginning of period		9		4		87		58		—			158			9		4		87		58		—			158

Cash and equivalents, end of period	$	4,847		1,177		3,391		327		—		$	9,742		$	8		2,040		4,363		319		—		$	6,730

~~Item 2.~~

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

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion updates “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in HEI’s 2004 Form 10-K and Form 10-Q for the ~~first~~second quarter of 2005 and should be read in conjunction with those reports and the annual (as of and for the year ended December 31, 2004) and quarterly (as of and for the three and six months ended ~~March 31,~~June 30, 2005) consolidated financial statements of HEI and HECO and accompanying notes.


(in thousands, except per share amounts)	Three months ended June 30,				% change		Primary reason(s) for significant change*	Three months ended September 30,				% change		Primary reason(s) for significant change*
(in thousands, except per share amounts)	2005		2004		% change		Primary reason(s) for significant change*	2005		2004		% change		Primary reason(s) for significant change*
Revenues	$	522,262	$	461,798	13		Increase for the electric utility and bank segments, slightly offset by a decrease for the “other” segment	$	595,915	$	506,759	18	%	Increase for all segments

Operating income		61,449		66,946	(8	)	Decrease for all segments		77,239		81,686	(5	)	Decreases for the electric utility and bank segments, partly offset by increase for the “other” segment
Income from:
Continuing operations								$	37,490	$	40,759	(8	)	Lower operating income and AFUDC and higher interest expense due to a higher short-term borrowings average balance
Discontinued operations									—		1,913	(100	)	HEIPC: 2004 gain on transfer of China joint venture interest

Net income		27,580		11,238	145		Impact in 2004 of an adverse bank franchise tax ruling ($24 million), partly offset by lower operating income and AFUDC and net loss from discontinued operations ($0.8 million for higher arbitration costs) in 2005	$	37,490	$	42,672	(12	)

Basic earnings per common share	$	0.34	$	0.14	143		Higher net income, partly offset by the impact of more common shares outstanding
Basic earnings per common share–
Continuing operations								$	0.46	$	0.51	(10	)
Discontinued operations									—		0.02	(100	)

								$	0.46	$	0.53	(13	)	See explanation for income above and weighted-average number of common shares outstanding below


Weighted-average number of common shares outstanding		80,814		80,350	1		Issuances of shares under Company stock option and non-employee director plans		80,903		80,509	—		Issuances of shares under Company stock option and non-employee director plans

The results of operations for the ~~second quarter~~first nine months of 2004 include a net charge of $24 million, or $0.30 per share, due to an adverse tax ruling as discussed in Note 4 of HEI’s “Notes to ~~HEI’s~~ Consolidated Financial Statements” under “ASB Realty Corporation.” The $24 million net charge includes a net $21 million of cumulative bank franchise taxes

through March 31, 2004, plus a net $3 million of interest (which gross interest of $5 million is included in general and administrative expenses of ASB). The following table presents a reconciliation of HEI’s consolidated income from continuing operations to income from continuing operations excluding this $24 million charge and including additional bank franchise taxes in prior periods as if the Company had not taken a dividends received deduction on income from its REIT subsidiary. The Company believes the adjusted information below presents results from continuing operations on a more comparable basis for the periods shown. However, net income, or earnings per share, including these adjustments is not a presentation defined under GAAP and may not be comparable to other companies or more useful than the GAAP presentation included in HEI’s consolidated financial statements.


	Three months ended June 30,				Six months ended June 30,					Nine months ended September 30
(in thousands, except per share amounts)	2005		2004		2005		2004			2005		2004
Income from continuing operations	$	28,335	$	11,238	$	52,430	$	42,170		$	89,920	$	82,929
Basic earnings per share - continuing operations	$	0.35	$	0.14	$	0.65	$	0.54		$	1.11	$	1.05

Cumulative franchise tax charge, net	$	—	$	23,955	$	—	$	23,955		$	—	$	23,955
Additional franchise taxes, net (if recorded in prior periods)		—		—		—		(634	)		—		(634	)

Total adjustments	$	—	$	23,955	$	—	$	23,321		$	—	$	23,321

As adjusted
Income from continuing operations	$	28,335	$	35,193	$	52,430	$	65,491		$	89,920	$	106,250
Basic earnings per share - continuing operations	$	0.35	$	0.44	$	0.65	$	0.83		$	1.11	$	1.34

Taking into account the adjustments in the table above, HEI’s consolidated income from continuing operations would have decreased ~~19% and 20%~~15% for the ~~three months and six~~nine months ended ~~June~~September 30, 2005, ~~respectively,~~ compared to the same ~~periods~~period last year as all segments had lower results.

See Note 87 of HEI’s “Notes to ~~HEI’s~~ Consolidated Financial Statements.”

For the first nine months of 2005, the retirement benefit plan assets generated a total return of 5.6%, resulting in realized and unrealized net gains of approximately $51 million, compared to a 9% annual expected return on plan assets assumption and a total return of 10.5% for 2004. The market value of the retirement benefit plans’ assets as of September 30, 2005 was $920 million. The Company made cash contributions to the retirement benefit (i.e., pension and other postretirement benefit) plans totaling $15 million for the first nine months of 2005 and intends to make additional cash contributions of $2 million by December 31, 2005.

Depending on the 2005 investment experience and interest rates at year-end (measurement date), the Company could be required to recognize an additional minimum liability at December 31, 2005 as prescribed by SFAS No. 87, “Employers’ Accounting for Pensions.” The recognition of an additional minimum liability is required if the accumulated benefit obligation exceeds the fair value of plan assets at measurement date. The recognition of an additional minimum liability would also result in the removal of the prepaid pension asset ($120 million at December 31, 2004) from the Company’s balance sheet. The liability would largely be recorded as a reduction to stockholders’ equity through a noncash charge to accumulated other comprehensive income (AOCI), and would not affect net income for 2005. The additional minimum liability does not apply to other postretirement benefits. Although the Company was not required to make any contributions to the pension plan to meet minimum funding requirements (under the Employee Retirement Income Security Act of 1974) in 2003 and 2004, the Company made pension contributions totaling $66 million in part to avoid the risk of a charge to AOCI that could have resulted if the accumulated benefit obligation had exceeded the fair value of plan assets at year-end.

The amount of additional minimum liability and charge to AOCI, if any, to be recorded at December 31, 2005, could be material and will depend upon a number of factors, including the year-end discount rate assumption, asset returns experienced in 2005, any changes to actuarial assumptions or plan provisions, and contributions made by the Company to the plans during 2005. In addition, retirement benefits expense and cash funding requirements could increase in future years depending on the performance of the equity markets and changes in interest rates.

In part, the Company benchmarks its discount rate assumption to the Moody’s Daily Long-Term Corporate Bond Aa Yield Average, which was 5.36% at September 30, 2005 compared to 5.66% at December 31, 2004. The discount rate used at December 31, 2004 was 6.00%. The Company anticipates the discount rate at December 31, 2005 will be between 5.50% and 6.00%.

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.

Based on the market value of the pension plans’ assets as of December 31, 2004 and assuming a range of returns on plan assets of 0% to 9% for 2005, cash contributions of $17 million in 2005, a range of 5.50% to 6.00% for the discount rate at December 31, 2005, and no further changes in assumptions or pension plan provisions, consolidated HEI’s, consolidated HECO’s and ASB’s AOCI balances, net of tax benefits, related to the minimum pension liabilities at December 31, 2005 are estimated to be as follows:

If the Company and consolidated HECO are required to record substantially greater charges to AOCI in the future, there may be possible financial covenant violations (although there are no advances currently outstanding under any credit facility subject to financial covenants) as certain bank lines of credit of the Company and HECO require that HECO maintain a minimum ratio of consolidated equity to consolidated capitalization as defined in the debt agreements of 35% (actual ratio of 56% as of September 30, 2005); the Company maintain a consolidated net worth, exclusive of intangible assets, of at least $900 million (actual net worth, exclusive of intangible assets, of $1.1 billion as of September 30, 2005); and HEI, on a non-consolidated basis, maintain a ratio of indebtedness to capitalization of not more than 50% (actual ratio of 27% as of September 30, 2005). Also, if prepaid pension assets that the electric utilities have been allowed to include in their rate bases for rate making purposes are eliminated, then the electric utilities’ reported rates of return on rate base (RORs) would be higher, which could impact the rates that the electric utilities are allowed to charge. (See discussion in “Most recent rate request” concerning the issue of including the prepaid pension asset in HECO’s rate base. In the HECO rate case, there was no issue among the parties with respect to including the estimated pension expense based on SFAS No. 87 in the test year expenses, but the Consumer Advocate and DOD proposed to exclude the estimated amount of the prepaid pension asset, net of the related accumulated deferred income taxes, from rate base.)

The electric utilities may submit a request for PUC approval to record, as a regulatory asset pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” the portion of any minimum pension liability charged directly to AOCI at a measurement date, as required by SFAS No. 87 and SFAS No. 130, including approval to adjust the aforementioned regulatory asset based on changes in the minimum pension liability amount at annual measurement dates thereafter. Under such an accounting treatment, if in future years the fair values of the electric utilities’ pension plan assets exceed their accumulated benefit obligations, the electric utilities would remove the regulatory assets and associated remaining minimum liabilities from their accounts. Under this approach, amortization of the regulatory assets would not be necessary. Management has not determined whether to submit such a request in 2005, and cannot predict with certainty whether the PUC would approve such a request.

Consolidated HEI’s, consolidated HECO’s and ASB’s net periodic pension and other postretirement benefits costs (net of tax benefits) are estimated to be $11 million, $8 million and $2 million, respectively, for 2005 compared to $7 million, $4 million and $2 million, respectively, for 2004.

Based on the market value of the retirement benefit plans’ assets as of December 31, 2004 and using the 9% return on plan asset assumption used in the estimation of a potential year-end AOCI charge above, 2006 retirement benefit expense, net of amounts capitalized and tax benefits, is expected to be:

Retirement benefit expenses based on net periodic pension and other postretirement benefit costs that are related to utility operations have been an allowable expense for rate-making, and higher benefit expenses, along with other factors, may affect the timing and amount of future electric rate increase requests.

On ~~July 26,~~November 9, 2005, HEI’s Board maintained the quarterly dividend of $0.31 per common share. The payout ratio for 2004 and the first ~~half~~nine months of 2005 was 90% and ~~97%~~85% (payout ratio of 91% and ~~95%~~84% based on income from continuing operations), respectively. HEI’s Board and management believe that HEI should achieve a 65% payout ratio on a sustainable basis before it considers increasing the common stock dividend above its current level.

Because its core businesses provide local electric utility and banking services, HEI’s operating results are significantly influenced by the strength of Hawaii’s economy. ~~In 2004, real gross state product grew by 5.6%, making~~The Bureau of Economic Analysis ranked Hawaii the 64^th fastest growing state in the U.S. in 2004. State economists ~~project~~reported 3.5% growth in 2004 with more modest growth for Hawaii of 3.1% in 2005 and ~~2.7%~~2.3% in 2006.

For the ~~state’s~~federal fiscal year ended September 30, 2003 (latest available data), total federal government expenditures in Hawaii, including military expenditures, were $11.3 billion, compared to $10.5 billion for fiscal year 2002. The 2003 total was $1.2 billion more than tourism expenditures for the same period. A 13% increase in military expenditures for fiscal year 2003 over fiscal year 2002 was the primary reason for the increase in total federal government expenditures. While ~~state~~ fiscal year 2004 statistics are not yet available ~~continued growth in total~~for federal government expenditures, continued growth is expected because Department of Defense expenditures increased 5% in fiscal year 2004 over fiscal year 2003 and several key military projects are expected to bring $3.8 billion in construction into the state over the next several years, including plans for an Army Stryker Brigade, the arrival of eight C-17 Air Force cargo planes and military housing renewal projects. ~~The Base Realignment and Closure Commission recently voted against adding Pearl Harbor Naval Shipyard to~~Offsetting such growth is the ~~list for possible closure or restructuring, preserving approximately 5,000 jobs at~~planned net deployments of Hawaii soldiers over the ~~Navy shipyard. There can be no assurances, however, that the shipyard or other military bases or operations will not be subject to closing in the future.~~

Tourism is widely acknowledged as a significant component of the Hawaii economy, second only to the federal government. ~~Visitor~~In 2004, visitor days—visitor arrivals multiplied by the average length of stay—~~are a key indicator of the trend in kilowatthour sales. In 2004, visitor days~~ hit a record 63 million, exceeding the record set in 2003 of 59 million by 7%. State economists expect visitor days to increase by ~~4.7%~~6.3% in 2005, largely due to the expectation that arrivals will top the previous record of just under 7 million set in 2000. Visitor days and expenditures were up ~~7.5%~~7.4% and 6%7.8%, respectively for the first ~~five~~eight months of 2005 compared with the same period of 2004.

Unemployment remains low. At the end of ~~June~~September 2005, Hawaii unemployment stood at 2.7% compared with the national unemployment rate of ~~5.0%~~5.1%.

The Hawaii construction industry remains healthy, due in part to military construction projects. Local economists forecast nominal contracting receipts to grow by ~~11%~~12% in 2005 as the privatization of military housing ramps-up. Growth in contracting receipts is expected to moderate to near 5% in 2006.

The price of Hawaii real estate ~~is expected~~continues to climb in 2005, reflecting tight inventory levels. Median single-family home prices on Oahu were ~~$593,300~~$615,000 in ~~June~~September 2005, ~~$98,300~~$120,000 more than the December 2004 Oahu median price of $495,000. ~~Inventory on Oahu remains tight which adds support for prices, but suppresses sales volumes.~~

Overall, the outlook for the Hawaii economy remains positive. However, economic growth is affected by the rate of expansion in the mainland U.S. and Japan economies and growth in military spending. It is also vulnerable to uncertainties in the world’s geopolitical environment.

Management monitors interest rates because ASB’s earnings are affected by changes in the interest rate environment. Generally, a flat yield curve is indicative of a difficult earning environment for ASB. As of ~~June~~September 30, 2005, the spread between the 2-year and 10-year Treasuries was ~~0.28%~~0.15%, compared to ~~0.70%~~0.28% at ~~March 31,~~June 30, 2005 and ~~1.89%~~1.15% at ~~June 30,~~December 31, 2004 (as this spread approaches zero, a flat yield curve is indicated).


(in thousands)	Three months ended June 30,						% change			Primary reason(s) for significant change		Three months ended September 30,							% change			Primary reason(s) for significant change
(in thousands)	2005			2004						Primary reason(s) for significant change	2005				2004				% change			Primary reason(s) for significant change
Revenues	$	586		$	1,211		% change	(52	)		Lower net investment income in 2005		$	7,145			$	6,386		12			Unrealized gain on a venture capital investment ($7 million), partly offset by 2004 gain on sale of income notes ($6 million)
Operating income													3,768				2,442		54			See explanation for revenues above and due to lower administrative and general expense
Net loss from continuing operations													(1,008	)			(794	)	(27	)		Higher interest expense and no preferred stock dividends from ASB in 2005, partly offset by higher operating income

(in thousands)												Nine months ended September 30,							% change			Primary reason(s) for significant change
(in thousands)												2005				2004						Primary reason(s) for significant change
Revenues												$	8,360			$	8,836		% change	(5	)		Unrealized gain on a venture capital investment ($7 million), more than offset by gain on sale of and higher income from income notes ($7 million) in 2004
Operating loss		(3,400	)		(1,979	)	NM			See explanation for “Revenues” above and due to higher administrative and general expenses, primarily compensation expense			(3,520	)			(1,948	)	(81	)		Higher administrative and general expenses, including compensation expenses

Net loss		(4,861	)		(3,548	)	NM			See explanation for “Operating loss” above and due to no preferred stock dividends from ASB in 2005, partly offset by lower income tax expense primarily due to the resolution of audit issues with the Internal Revenue Service
Net loss from continuing operations													(11,920	)			(9,360	)	(27	)		Higher operating loss and no preferred stock dividends from ASB in 2005, partly offset by lower interest expense and higher tax benefits primarily due to the resolution of audit issues with the Internal Revenue Service

The “other” business segment includes results of operations of HEI Investments, Inc. (HEIII), a company primarily holding investments in leveraged leases; Pacific Energy Conservation Services, Inc., a contract services company primarily providing windfarm operational and maintenance services to an affiliated electric utility; HEI Properties, Inc. (HEIPI), a company holding passive investments; Hycap Management, Inc. (which is in dissolution); The Old Oahu Tug Service, Inc., a maritime freight transportation company that ceased operations in 1999; HEI and HEIDI, holding companies; and eliminations of intercompany transactions. The first ~~half~~nine months of 2004 also includes the results of operations for unconsolidated subsidiaries, Hawaiian Electric Industries Capital Trust I and its subsidiary (HEI Preferred Funding, LP), which were dissolved in April 2004 and terminated in December 2004. Together with Hycap Management, Inc., these were financing entities formed to effect the issuance in 1997 of 8.36% Trust Originated Preferred Securities that were redeemed in April 2004.

See Note 913 of HEI’s “Notes to ~~HEI’s~~ Consolidated Financial Statements” for a discussion of the closing of HEIII’s ~~agreement to sell~~sale of its interest in a leveraged lease ~~asset.~~asset in October 2005.

See Note 5 of HEI’s “Notes to ~~HEI’s~~ Consolidated Financial Statements.”

See Note 98 of HEI’s “Notes to ~~HEI’s~~ Consolidated Financial Statements.”

See Note 1110 of HEI’s “Notes to ~~HEI’s~~ Consolidated Financial Statements.”

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

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


(in millions)	June 30, 2005				December 31, 2004				September 30, 2005				December 31, 2004
Short-term borrowings	$	127	5	%	$	77	3	%	$	121	5	%	$	77	3	%
Long-term debt, net		1,168	46			1,167	47			1,173	46			1,167	47
Preferred stock of subsidiaries		34	1			34	1			34	1			34	1
Common stock equity		1,216	48			1,211	49			1,213	48			1,211	49

	$	2,545	100	%	$	2,489	100	%	$	2,541	100	%	$	2,489	100	%

As of ~~July~~October 31, 2005, the Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HEI securities were as follows:

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

~~dated May 31, 2005.~~&P stated “a final order that closely mirrors the interim ruling appears to be sufficient to lift key financial metrics to levels that are marginally suitable for Standard & Poor’s guideposts for the ‘BBB’ rating category.” However, S&P will maintain its negative outlook until the PUC issues its final order. In addition, S&P ranks business profiles from ~~‘1’~~“1” (strong) to ~~‘10’~~“10” (weak). There was no change in HEI’s business profile rank of ~~‘6’~~“6”. Moody’s maintains a stable outlook on HEI.

At ~~June~~September 30, 2005, an additional $96 million of debt, equity and/or other securities were available for offering by HEI under an omnibus shelf registration, and an additional $150 million principal amount of Series D notes were available for offering by HEI under its registered medium-term note program.

HEI periodically utilizes short-term debt, principally commercial paper, to support normal operations and for other temporary requirements. ~~HECO~~HEI also periodically ~~borrows~~makes short-term ~~from HEI for itself~~loans to HECO to meet HECO’s cash requirements and on behalf of HELCO and MECO. HEI had short-term loans to HECO of $13 million at September 30, 2005. HEI had an average outstanding balance of commercial paper for the first ~~six~~nine months of 2005 of $1$2 million and had $4$8 million outstanding at ~~June~~September 30, 2005. Management believes that if HEI’s commercial paper ratings were to be downgraded, it might not be able to sell commercial paper under current market conditions.

At ~~June~~September 30, 2005, HEI maintained bank lines of credit with four different banks totaling $80 million ($45 million expiring in the fourth quarter of 2005 and $35 million expiring in 2006). These lines of credit are ~~principally~~ maintained by HEI principally to support the issuance of commercial paper, but also may be drawn for general corporate purposes. Accordingly, the lines of credit are available for short-term liquidity in the event a rating agency downgrade were to reduce or eliminate access to the commercial paper markets. Lines of credit to HEI totaling $30 million contain provisions for revised pricing in the event of a ratings change (e.g., a ratings downgrade of HEI

medium-term notes from BBB/Baa2 to BBB-/Baa3 by S&P and Moody’s, respectively, would result in a 12.5 to 50 basis points higher interest rate; a ratings upgrade from BBB/Baa2 to BBB+/Baa1 by S&P and Moody’s, respectively, would result in a 12.5 to 20 basis points lower interest rate). There are no such provisions in HEI’s other lines of credit. None of HEI’s line of credit agreements contain clauses that would affect access to the lines by reason of a ratings downgrade, nor do they have broad “material adverse change” clauses that could affect access to the lines in the event of any material adverse event so long as any such event is timely disclosed. However, access to some or all of the lines could be restricted, or defaults under the lines could occur, if representations and warranties in the agreements, as permitted to be updated, are not true and correct at the time an advance is requested or if HEI is not in compliance with the covenants in such agreements. Management believes that it is not likely that any such restriction or default will occur. At ~~June~~September 30, 2005, the lines were ~~unused.~~undrawn. To the extent deemed necessary, HEI anticipates arranging similar lines of credit as existing lines of credit expire.

For the first ~~six~~nine months of 2005, net cash provided by operating activities of consolidated HEI was ~~$70~~$156 million. Net cash used in investing activities for the same period was ~~$52~~$207 million due to ~~ASB’s originations and purchases of~~a net increase in loans ~~net of repayments,~~receivable at ASB, and HECO’s consolidated capital expenditures, partly offset by repayments and sales of mortgage-related securities held by ASB, net of purchases, and contributions in aid of construction at the electric utilities. Net cash provided by financing activities during this period was ~~$36~~$112 million as a result of several factors, including net increases in deposit liabilities, short-term borrowings, advances from the FHLB and long-term debt and proceeds from issuances of common stock, partly offset by a net decrease in securities sold under agreements to repurchase and the payment of common stock dividends.

Following are discussions of the results of operations, liquidity and capital resources of the electric utility and bank segments.


(dollars in thousands, except per barrel amounts)	Three months ended June 30,				% change		Primary reason(s) for significant change	Three months ended September 30,				% change		Primary reason(s) for significant change
(dollars in thousands, except per barrel amounts)	2005		2004		% change		Primary reason(s) for significant change	2005		2004		% change		Primary reason(s) for significant change
Revenues	$	429,730	$	370,605	16		Higher KWH sales ($7 million) and higher fuel oil and purchased energy fuel costs, the effects of which are generally passed on to customers ($49 million)	$	491,339	$	410,077	20		Higher fuel oil and purchased energy fuel costs, the effects of which are generally passed on to customers ($76 million)

Expenses

Fuel oil		148,775		114,496	30		Higher fuel oil costs and more KWHs generated		182,663		128,584	42		Higher fuel oil costs

Purchased power		106,369		94,267	13		Higher fuel costs and more KWHs purchased		122,086		105,985	15		Higher fuel costs

Other		131,939		115,928	14		Higher other operation and maintenance expenses, depreciation and taxes, other than income taxes		139,057		122,795	13		Higher other operation and maintenance expenses, depreciation and taxes, other than income taxes

Operating income		42,647		45,914	(7	)	Higher KWH sales, more than offset by higher expenses		47,533		52,713	(10	)	Higher expenses

Net income		19,644		21,735	(10	)	Lower operating income and AFUDC		22,587		26,175	(14	)	Lower operating income and AFUDC and higher interest expense due to a higher short-term borrowings average balance and short-term interest rates

Kilowatthour sales (millions)		2,519		2,473	2		Warmer weather		2,672		2,675	—		Load growth, more than offset by the impact of less humid weather and load loss due to major commercial repair and renovation projects

Oahu cooling degree days (CDD)		1,471		1,320	11				1,649		1,651	—

Fuel oil cost per barrel	$	51.90	$	40.43	28			$	59.72	$	42.72	40


(dollars in thousands, except per barrel amounts)	Six months ended June 30,				% change		Primary reason(s) for significant change	Nine months ended September 30,				% change		Primary reason(s) for significant change
(dollars in thousands, except per barrel amounts)	2005		2004		% change		Primary reason(s) for significant change	2005		2004		% change		Primary reason(s) for significant change

Revenues	$	804,505	$	717,218	12		Higher KWH sales ($2 million) and higher fuel oil and purchased energy fuel costs, the effects of which are generally passed on to customers ($82 million)	$	1,295,844	$	1,127,295	15		Higher KWH sales ($3 million) and higher fuel oil and purchased energy fuel costs, the effects of which are generally passed on to customers ($158 million)

Expenses

Fuel oil		264,401		211,582	25		Higher fuel oil costs, partly offset by less KWHs generated		447,064		340,166	31		Higher fuel oil costs, partly offset by less KWHs generated

Purchased power		207,585		186,506	11		Higher fuel costs and more KWHs purchased		329,671		292,491	13		Higher fuel costs and more KWHs purchased

Other		258,266		229,076	13		Higher other operation and maintenance expenses, depreciation and taxes, other than income taxes		397,323		351,871	13		Higher other operation and maintenance expenses, depreciation and taxes, other than income taxes

Operating income		74,253		90,054	(18	)	Higher KWH sales, more than offset by higher expenses		121,786		142,767	(15	)	Higher KWH sales, more than offset by higher expenses

Net income		32,029		41,758	(23	)	Lower operating income and AFUDC		54,616		67,933	(20	)	Lower operating income and AFUDC

Kilowatthour sales (millions)		4,866		4,841	1		Slightly warmer weather		7,538		7,516	—		Load growth, partly offset by the impact of less humid weather and load loss due to major commercial repair and renovation projects

Oahu cooling degree days (CDD)		2,251		2,232	1				3,900		3,883	—

Fuel oil cost per barrel	$	48.96	$	39.08	25			$	52.85	$	40.38	31

See “Pension and other postretirement benefits” and “Economic conditions” in the “HEI Consolidated” section above.

Kilowatthour (KWH) sales in the ~~second~~third quarter of 2005 ~~increased 1.8% from~~were flat when compared to the ~~second~~same quarter in 2004 as new load growth (i.e., increase in the number of ~~2004, primarily due to warmer weather.~~customers) was more than offset by the impacts of less humid weather and major commercial repair and renovation projects (which resulted in temporary load loss). Although KWH sales ~~increased,~~were flat, operating income decreased 7%10% from the ~~second~~third quarter 2004, primarily due to higher expenses other ~~expenses.~~than for fuel oil and purchased power. Other operation expense increased ~~13% partly~~7% primarily due to higher ~~production,~~ transmission and distribution operations expense and higher ~~pension~~retirement benefits expense. Pension and other postretirement benefit expenses for the electric utilities increased $2$1.6 million over the same period in 2004 due in part to a 25 basis points lower discount rate at December 31, 2004. Maintenance expense increased by ~~25%~~23% due to $1.6 million higher production maintenance expense (primarily ~~the greater number of overhauls and~~ higher steam generation station maintenance) and $2.3 million higher transmission and distribution maintenance ~~expense (primarily higher substation maintenance and vegetation management).~~expense. Further, other operation and maintenance expenses were higher partly due to increased staffing and other costs to support increased demand, reliability and customer service ~~and energy efficiency~~ programs. Higher depreciation expense was attributable to additions to plant in service in 2004 (including HELCO’s CT-4 and CT-5 and HECO’s Waiau fuel oil pipeline), offset in part by lower depreciation expense resulting from the PUC’s approval in September 2004 of changes in the depreciation rates and accounting methodology applicable to HECO’s depreciable assets on Oahu.

KWH sales in the first ~~half~~nine months of 2005 increased ~~0.5%~~0.3% from the ~~first half of~~same period in 2004, primarily due to ~~slightly warmer weather.~~new load growth (i.e., increase in number of customers), largely offset by the impacts of less humid weather and major commercial repair and renovation projects. Although KWH sales increased slightly, operating income decreased ~~18%~~15% from the ~~first half of~~same period in 2004, primarily due to higher other expenses. Other operation expense increased ~~17% partly~~13% primarily due to higher expenses for production operations (including higher environmental expense as there was a DOH emission fee waiver in the first quarter of 2004, which was not repeated in the first quarter of 2005),

transmission and distribution operations (due in part to increased line inspections) and retirement benefits ~~and compliance with the Sarbanes-Oxley Act of 2002 (SOX).~~expense. Pension and other postretirement benefit expenses for the electric utilities increased $3$4.9 million over the same period in 2004 due in part to a 25 basis points lower discount rate at December 31, 2004. Maintenance expense increased by ~~15%~~18% due to higher production maintenance expense (primarily ~~the increased scope of the overhaul of an Oahu CT peaking unit, Waiau Unit 9 with a capability of 51.9 MW), more generating unit overhauls,~~due to higher steam generation station maintenance and more generating unit overhauls) and higher transmission and distribution maintenance expense ~~(primarily~~(due in part to higher substation maintenance and higher vegetation management). Higher depreciation expense was attributable to additions to plant in service in 2004 (including HELCO’s CT-4 and CT-5 and HECO’s Waiau fuel oil pipeline), offset in part by lower depreciation expense resulting from the PUC’s approval in September 2004 of changes in the depreciation rates and accounting methodology applicable to HECO’s depreciable assets on Oahu.

The trend of increased operation and maintenance expenses is expected to continue in 2005 as the electric utilities anticipate: (1) higher demand-side management ~~and integrated resource planning~~ expenses (that are passed on to customers through a surcharge and therefore do not impact net income), and integrated resource planning expenses, (2) higher employee benefits expenses, primarily for retirement benefits and (3) higher production expenses, primarily to meet higher demand levels and load ~~growth.~~growth set in 2004 and sustained in 2005. The timing and amount of these expenses can vary as circumstances change. For example, recent overhauls have been more expensive than in the past due to the larger scope of work necessary to maintain the aging equipment, which has experienced heavier usage as demand has increased. In October 2004, one of HECO’s two CTs, Waiau Unit 9, experienced a sudden and accidental breakage of a blade that subsequently caused a catastrophic failure of the entire turbine. Greater customer demand resulting in higher usage of Waiau Unit 9 contributed to the failure. While partially covered by insurance, the repair costs are significant additional expenses necessary for service reliability. HECO completed the overhaul of Waiau Unit 9 in April 2005 and preventive overhaul work on its other CT, Waiau Unit 10 (with a capability of 49.9 MW) ~~is planned~~, has been deferred for a few months to ~~begin later in 2005.~~work on another unit. These Oahu peaking units have been used more frequently to meet increased customer demand for extended periods. Although it will not be known until the overhaul is fully underway, it is possible that the maintenance costs for Waiau Unit 10 will be higher than originally planned. Increased operation and maintenance expenses iswas one of the reasons HECO filed a request with the PUC in November 2004 to increase base rates.

Although competition in the generation sector in Hawaii has been moderated by the scarcity of generation sites, various permitting processes and lack of interconnections to other electric utilities, HECO and its subsidiaries face competition from IPPs and customer self-generation, with or without cogeneration.

In 1996, the PUC issued an order instituting a proceeding to identify and examine the issues surrounding electric competition and to determine the impact of competition on the electric utility infrastructure in Hawaii. In October 2003, the PUC closed the competition proceeding and opened investigative proceedings on two specific issues (competitive bidding and DG) to move toward a more competitive electric industry environment under cost-based regulation.

Competitive bidding proceeding. The current parties/participants in the competitive bidding proceeding include the Consumer Advocate, HECO, HELCO, MECO, Kauai Island Utility Cooperative, the County of Kauai and a renewable energy ~~organization and a vendor of DG equipment and services. In June 2005, the PUC filed a Notice of Intent to Dismiss another vendor of DG equipment and services from the proceeding.~~organization. The issues to be addressed in the proceeding include the benefits and impacts of competitive bidding, whether a competitive bidding system should be developed for acquiring or building new generation, and revisions that should be made to integrated resource planning. If it is determined that a competitive bidding system should be developed, issues include how a fair system can be developed that “ensures that competitive benefits result from the system and ratepayers are not placed at undue risk”, what the guidelines and requirements for prospective bidders should be, and how such a system can encourage broad participation. Statements of Position by, information requests to, and responses by the parties/participants were filed in March through June 2005. Final ~~Statements~~statements of ~~Position are due~~position were filed in August ~~2005 and evidentiary~~2005. The PUC has indicated that panel hearings ~~are scheduled~~will be held in ~~October~~December 2005. Management cannot predict the ultimate outcome of this proceeding or its effect on the ability of the electric utilities to acquire or build additional generating capacity in the future. The PUC stated it would consider related matters on a case-by-case basis pending completion of the competitive bidding and DG proceedings.

Distributed generation proceeding. The number of customer self-generation projects that are being proposed or installed in Hawaii, particularly those involving CHP systems, is growing. CHP systems are a form of DG, and produce electricity and thermal energy, which is generally used in Hawaii to heat water and, through an absorption chiller, drive an air conditioning system. The electric energy generated by these systems is usually lower in output than the customer’s load, which results in the customer’s continued connection to the utility grid to make up the difference in electricity demand and to provide back up electricity.

Over the last several years, the electric utilities have been exploring the possibility of utility-owned, customer sited CHP systems. Incremental generation from such customer-sited CHP systems, and other DG, is expected to complement traditional central station power, as part of the electric utilities’ plans to meet their forecast load growth.

In July 2003, three vendors of DG/CHP equipment and services requested, in an informal complaint, that the PUC investigate the electric utilities’ provision of CHP services and their teaming agreement with another vendor (which teaming agreement has since been cancelled), and issue rules or orders to govern the terms and conditions under which the electric utilities will be permitted to engage in utility-owned, customer sited DG.

In October 2003, the PUC opened the DG proceeding to determine the potential benefits and impact of DG on Hawaii’s electric distribution systems and markets and to develop policies and a framework for DG projects deployed in Hawaii. The parties and participants to the proceeding include the Consumer Advocate, HECO, HELCO, MECO, Kauai Island Utility Cooperative, the Counties of Maui and Kauai, a renewable energy organization, a vendor of DG equipment and services and an environmental organization.

In April 2004, the PUC issued an order in the DG proceeding defining issues related toplanning (forms of DG, who should own and operate projects, and the roles of the electric utilities and PUC),impacts (the impacts, if any, on the transmission and distribution systems and market, power quality and reliability, the use of fossil fuels, utility costs and external costs and benefits) andimplementation (matters to be considered to allow a DG facility to interconnect with the utility’s grid, appropriate rate design and cost allocation issues, revisions that should be made to the integrated resource planning process, and revisions that should be made to PUC and utility rules and practices). In the proceeding, the parties and participants also were allowed to address issues raised in the informal complaint, but

not specific claims made against any parties named in the complaint. Hearings were held in December 2004. A decision from the PUC is expected in the ~~third or~~ fourth quarter of 2005. Management cannot predict the ultimate outcome of this proceeding.

Prior to opening of the investigative DG proceeding, the electric utilities filed an application for approval of CHP tariffs, under which they would own, operate and maintain customer-sited, packaged CHP systems (and certain ancillary equipment) pursuant to standard form contracts with eligible commercial customers. Pending approval of the proposed CHP tariffs, HECO and HELCO each requested in the fourth quarter of 2004 PUC approval of an agreement with a customer for a utility CHP project. The PUC suspended the applications for approval of the CHP tariffs and CHP project agreements until, at a minimum, the matters in the investigative DG proceeding have been adequately addressed. Subsequently, the HECO customer exercised its right to terminate the CHP project agreement and the application for approval of the project was withdrawn. The HELCO CHP agreement remains in suspension. With the continued suspension of HECO’s CHP Program application and the suspension of HECO’s and HELCO’s applications for individual CHP projects, management cannot predict if or when the benefits of utility CHP can begin to be realized.

~~HEI’s~~The electric utilities initiate PUC proceedings from time to time to request electric rate increases to cover rising operating costs (e.g., higher energy conservation and efficiency program costs and higher purchased power capacity charges) and the cost of plant and equipment, including the cost of new capital projects to maintain and improve service reliability. As of ~~July~~October 31, 2005, the return on average common equity (ROACE) found by the PUC to be reasonable in the most recent final rate decision for each utility was 11.40% for HECO (D&O issued on December 11, 1995, based on a 1995 test year), 11.50% for HELCO (D&O issued on February 8, 2001, based on a 2000 test year) and 10.94% for MECO (amended D&O issued on April 6, 1999, based on a 1999 test year). For the 12 months ended June 30, 2005, the simple average ROACEs (calculated under the rate-making method and reported to the ~~PUC)~~PUC semi-annually) for HECO, HELCO and MECO were 6.92%, 6.97% and 9.68%, respectively.

HELCO’s ROACE will continue to be negatively impacted by CT-4 and CT-5 as electric rates will not change for the unit additions until HELCO files a rate increase application and the PUC grants HELCO rate relief. HECO’s actual ROACE is significantly lower than its allowed ROACE primarily because of increased operation and maintenance (O&M) expenses, which are expected to continue. ~~HECO’s ROACE is expected to remain lower until~~The PUC has granted HECO interim rate relief, effective September 28, 2005 (see below), which is ~~granted~~based in ~~the pending rate case~~part on increased costs of operating and ~~impacts earnings for a full year.~~maintaining its system.

As of ~~July~~October 31, 2005, the return on average rate base (ROR) found by the PUC to be reasonable in the most recent final rate decision for each utility was 9.16% for HECO, 9.14% for HELCO and 8.83% for MECO (D&Os noted above). For the 12 months ended June 30, 2005, the simple average RORs (calculated under the rate-making method and reported to the ~~PUC)~~PUC semi-annually) for HECO, HELCO and MECO were 6.29%, 6.64% and 8.45% (after reduction of MECO’s revenues from shareholder incentives and lost margins in December 2004), respectively.

The ROACE and ROR used in determining HECO’s revenue requirements in the latest Interim D&O were 10.7% and 8.66%, respectively (see below).

If required to record significant charges to accumulated other comprehensive income (AOCI) related to a minimum liability for retirement benefits, the electric utilities’ RORs could increase and exceed the PUC authorized RORs, which may ultimately result in reduced revenues and lower earnings.

Hawaiian Electric Company, Inc. The final D&O for the last rate case for HECO on Oahu was issued in 1995.

In November 2004, HECO filed a request with the PUC to increase base rates 9.9%, or $98.6 million in annual base revenues, based on a 2005 test year, a 9.11% return on rate base and an 11.5% return on average common equity. As a result of PUC-approved stipulations in 2001, as modified in 2002, HECO requested approval of its proposed new energy efficiency (EE) DSM programs (Enhanced EE DSM programs), and associated utility incentive mechanism, in its rate case application, and included the related costs in its proposed rate increase. The requested increase included transferring the cost of existing DSM programs from a surcharge line item on electric bills into base electricity charges. Excluding this surcharge transfer amount, the requested net increase to customers was 7.3%, or $74.2 million, largely for (1) the costs ofnew DSM programs, (2) the costs of capital improvement projects completed since the last rate case, (3) the proposed purchase of up to an additional 29 MW of firm capacity and energy from Kalaeloa Partners, L.P., (4) other measures taken to address peak load increases arising out of economic growth and increasing electricity use, and (5) increased O&M expenses. The PUC held a public hearing in January 2005. In addition to HECO, the parties include the Consumer Advocate and the ~~Department of Defense (DOD).~~DOD.

In March 2005, the PUC issued a bifurcation order separating HECO’s requests for approval and/or modification of its existing and proposed DSM programs from the rate case proceeding into a new docket. The preliminary issues identified by the PUC for the new EE DSM Docket include (1) whether, and if so, what, energy efficiency goals should be established, (2) whether the proposed and/or other DSM programs will achieve the established energy efficiency goals and be implemented in a cost-effective manner, (3) what market structures are most appropriate for providing these or other DSM programs, and (4) for utility-incurred costs, what cost recovery mechanisms and cost levels are appropriate. The original parties/participants in this docket included HECO, the Consumer Advocate, the Department of Defense, the County of Maui, two renewable energy organizations, an energy efficiency organization, and an environmental organization. In June 2005, however, the PUC, on its own initiative, included HELCO, MECO, Kauai Island Utility Cooperative and The Gas Company as parties to the docket, provided their participation is limited solely to the issues dealing with statewide energy policies. In June 2005, the County of Kauai filed a motion to participate or intervene and Honolulu Seawater Air Conditioning, LLC filed a motion to intervene and a motion to extend the time to file that motion (which was filed after the PUC’s deadline). In August 2005, the PUC denied these motions. A schedule for the EE DSM Docket has not yet been established.

As a result of the bifurcation order, HECO ~~will continue~~is continuing its existing DSM programs and cost recovery mechanisms (under which program costs, shareholder incentives, and lost margins between rate cases, are covered through a DSM surcharge). Relevant provisions of the stipulations under which the existing DSM programs have been extended ~~will~~ continue to apply, including an agreement to cap the recovery of lost margins and shareholder incentives, if such recovery would cause HECO to exceed its current “authorized” ROR (i.e., the ROR found by the PUC to be reasonable in the most recent rate case for HECO, which, as a result of the Interim D&O discussed below, is currently ~~9.16%~~8.66%). An estimated $32 million in revenue requirements for DSM program costs related to both the Enhanced EE DSM programs and to the existing DSM programs, to the extent recovered through the DSM surcharge, ~~has been~~were thus removed from ~~the~~HECO’s rate increase request.

The base rate increase included in HECO’s rebuttal testimonies and exhibits filed in the proceeding in August 2005 ~~is now~~was $63 million, or 5.2%, rather than $98.6 million, or 9.9%. The reduced request ~~reflects~~reflected removal of the revenue requirements for existing DSM program costs recovered through a surcharge and the cost of the proposed Enhanced EE DSM programs, slightly higher estimated sales due to lower DSM program impacts as the enhanced DSM proposals are ~~being~~now to be considered in the EE DSM Docket, changes in certain O&M expenses and rate base components for the 2005 test year based on updated information and actual year-end 2004 balances, and a lower proposed ROACE and ROR of 11% and 8.83%, respectively.

The revised and updated $63 million increase ~~includes~~requested in August 2005 included the transfer to base rates of certain costs related to existing energy efficiency programs from a surcharge line item on electric ~~bills into base electricity charges.~~bills. Excluding this surcharge transfer amount, the revised requested net increase to customers is 4.1%, or $50.9 million. (The costs to be transferred from a surcharge to base electric rates are primarily for lost margins. HECO currently is allowed to recover lost margins (i.e., lost revenues net of variable costs) due to the impact of its existing energy efficiency DSM programs on sales between rate cases. In rate cases, the impact of DSM programs on test year sales can be directly taken into account and incorporated into the calculation of base rates. Only future lost margins will be recovered through the surcharge after new rates are set, and the continued recovery of lost margins will be reviewed in the EE DSM Docket.)

In its testimonies and exhibits filed at the end of June 2005, the CAConsumer Advocate had proposed a rate increase of $23.5 million, based on its proposed ROR of 7.85% and a ROACE ranging between 8.50% and 10.0%. The remaining party, the DOD, in testimony and exhibits filed in June and July 2005, had proposed a rate increase of $19.3 million, based on its proposed ROR of 7.71% and ROACE of 9%. These proposals also excluded revenue requirements for DSM program costs. The HECO, Consumer Advocate and DOD RORs are based on rate bases of $1.109 billion, $1.065 billion and $1.062 billion, respectively. ~~Based upon~~

In September 2005, HECO, the ~~testimony~~Consumer Advocate and the DOD reached agreement among themselves on most of the issues in the rate case proceeding, subject to PUC approval. Under the agreement, HECO’s revised request was lowered from the $63 million requested in August 2005 to $54 million, or 4.4% ($42 million, or 3.4%, excluding the surcharge transfer amount). The remaining significant issue among the parties is the appropriateness of including in rate base approximately $50 million related to HECO’s prepaid pension asset, net of deferred income taxes. An evidentiary hearing on this issue, with a rate increase impact of approximately $7 million, was held in September 2005. For purposes of the Interim D&O (described below), the PUC included HECO s prepaid pension asset in rate base in determining HECO’s revenue requirements.

In a rate case, the PUC may grant an interim rate increase (subject to refund with interest pending the final outcome of the case) if the PUC believes that the public utility is probably entitled to an increase in its rates. On September 27, 2005, the PUC issued an Interim D&O granting an increase of 4.36%, or $53.3 million (3.33%, or $41.1 million excluding the surcharge transfer amount). The tariff changes implementing the interim rate increase were effective September 28, 2005. If the amount collected pursuant to this interim rate increase exceeds the amount of the increase approved in the final D&O, then the excess must be refunded to HECO’s ratepayers, with interest. The interim rate increase is based on a ROACE of 10.7%, a ROR of 8.66% and rate base of $1.109 billion. However, the adoption of revenue, expense, rate base and cost of capital amounts (including the ROACE and ROR) for purposes of an ~~expert witness and rates of return given~~interim rate increase does not commit the PUC to ~~electric utilities~~accept any such amounts in ~~recent rate cases across the country, HECO management believes~~ its proposed rates of return to be fair and reasonable. The issue of returns will be deliberated further in the regulatory process which is still underway. Evidentiary hearings are scheduled to begin on September 13, 2005. An interim decision is expected in the fourth quarter of 2005.

Hawaii Electric Light Company, Inc. The timing of a future HELCO rate increase request to recover costs, including cost for the installation of two combustion turbines (CT-4 and CT-5) at Keahole, will depend on future circumstances. See “HELCO power situation” in Note 5 of HECO’s “Notes to ~~HECO’s~~ Consolidated Financial Statements.”

The PUC has broad discretion in the regulation of the rates charged by the electric utilities and other matters. Any adverse D&O by the PUC concerning the level or method of determining electric utility rates, the authorized returns on equity, or other matters, or any prolonged delay in rendering a D&O in a rate or other proceeding could have a material adverse affect on the Company’s and HECO’s consolidated results of operations and financial condition. Management cannot predict with certainty when D&O’s in the current HECO rate case or in future rate cases will be rendered or the amount of any interim or final rate increase that may be granted.

In October 2002, HECO filed an application with the PUC for approval to change its depreciation rates based on a study of depreciation expense for 2000 and to change to vintage amortization accounting for selected plant accounts. In March 2004, HECO and the Consumer Advocate reached an agreement, which the PUC approved in September 2004. In accordance with the agreement, HECO changed its depreciation rates and changed to vintage amortization accounting for selected plant accounts effective September 1, 2004, resulting in slightly lower depreciation than would have been recorded under the previous rates and method.

Integrated resource planning and requirements for additional generating capacity

In August 2000, pursuant to a stipulation filed by the electric utilities and the parties in the IRP cost proceedings, the PUC issued an order allowing the electric utilities to begin recovering the 1995 through 1999 incremental IRP costs, subject to refund with interest, pending the PUC’s final D&O approving recovery of each respective year’s incremental IRP costs. Incremental IRP costs are deferred until approved for recovery, at which time they are amortized to expense. Procedural schedules for the IRP cost proceedings have been established with respect to the 2000-2004 IRP costs, such that the electric utilities can begin recovering incremental IRP costs in the month after the filing of the actual costs incurred for the year, subject to refund with interest, pending the PUC’s final D&O approving recovery of the costs. HECO completed recovery of its 2004 incremental IRP costs in August 2005 and MECO is scheduled to complete recovery of its 2004 costs in June 2006. The Consumer Advocate has objected to the recovery of $3.2 million (before interest) of the $11.8 million of incremental IRP costs incurred during the 1995-2004 period, and the PUC’s decision is pending on this matter.

In September 2003, the PUC opened a docket to commence HECO’s third Integrated Resource Plan (IRP-3), which HECO was ordered by the PUC to file by October 31, 2005. ~~In June~~On October 28, 2005, HECO ~~published a draft IRP for public review and comments. The draft IRP~~filed its IRP-3, which proposes multiple solutions to meet Oahu’s future energy needs, including renewable energy resources, energy efficiency, conservation, technology (such as CHP) and central station generation. IRP-3 included a potential wind energy project above HECO’s Kahe power plant. However, HECO currently plans to review other potential sites due to the Mayor of Honolulu’s opposition to the project site.

In June 2005, HECO filed with the PUC an application for approval of funds to build a new nominal 100 MW simple cycle combustion turbine generating unit at Campbell Industrial Park on Oahu, the site of three other existing power plants, each owned and operated by an IPP (AES Hawaii, Kalaeloa and H-POWER). Plans are for the combustion turbine to be run primarily as a “peaking” unit beginning in 2009, operating mainly between the weekday peak electricity demand periods or during times when other generating units are not available. The air permit application for the unit, filed in October 2003 and currently under review by the DOH, requests approval to burn naphtha or diesel and specifies that the unit will have the ability to convert to using biofuels, such as ethanol, when they are commercially available. HECO is currently in the process of reviewing proposals received in May 2005 for the combustion turbine from three vendors through a competitive bidding process. Selection of the combustion turbine will be made through an evaluation of pricing, performance and commercial terms. Management expects to execute a contract with the selected vendor prior to year-end, with the right to terminate the contract at a specified payment amount if necessary CT project approvals are not obtained.

The generating unit application also requests approval to build an additional 138 kV transmission line approximately two miles long, within and adjacent to Campbell Industrial Park, to more reliably transmit power from the new and existing generating units within the industrial park to the Oahu electric grid. Preliminary costs for the new generating unit and transmission line, as well as related substation improvements, are estimated at $134 million. As of ~~June~~September 30, 2005 accumulated project costs for planning, engineering, permitting and AFUDC amounted to ~~$1.6~~$1.9 million. HECO is now preparing an Environmental Impact Statement for the proposed project.

In a related application filed with the PUC in June 2005, HECO requested approval for an approximately $11.5 million package of community benefit measures to mitigate the impact of the new generating unit on communities near the proposed generating unit site. These measures include a base electric rate discount for those who live near the proposed generation site, additional air-quality monitoring stations, a fish monitoring program and the use of recycled instead of potable water in Kahe power plant’s operations.

In July 2005, the Consumer Advocate filed Preliminary Statements of Position on HECO’s Campbell Industrial Park generating unit and transmission line additions application and community benefits application. Also in

July 2005, HECO filed memoranda in response opposing the Consumer Advocate’s recommendations to suspend the two applications, suspend the start of the procedural schedule for both applications until after the filing of the IRP-3 ~~Report~~ (which ~~is expected to be~~was filed ~~in September~~on October 28, 2005), and consolidate the applications.

In September 2005, the PUC suspended HECO’s Campbell Industrial Park generating unit and transmission line additions application until further order of the PUC to allow more time to review the application. Also in September 2005, the PUC ordered HECO and the Consumer Advocate to submit a stipulated prehearing order for the community benefits application within 30 days following the filing of HECO’s IRP-3 (i.e., by November 28, 2005).

~~Avoided cost generic docket.~~In May 1992, the PUC instituted a generic investigation, including all of Hawaii’s electric utilities, to examine the proxy method and formula used by the electric utilities to calculate their avoided energy costs and Schedule Q rates. In general, Schedule Q rates are available to customers with cogeneration and/or small power production facilities with a capacity of 100 KWHs or less who buy/sell power from/to the electric utility. The parties to the 1992 docket include the electric utilities, Consumer Advocate, Department of Defense, and representatives of existing or potential IPPs. In March 1994, the parties entered into and filed a Stipulation to Resolve Proceedings, which is subject to PUC approval. The parties could not reach agreement with respect to certain of the issues, which are addressed in

Statements of Position filed in March 1994. No further action was taken in the docket until July 2004 when the PUC ordered the parties to review and update, if necessary, the agreements, information and data contained in the stipulation and file such information and stated that further action will follow. ~~The requested information is scheduled~~In October 2005, the PUC approved a request from the parties for an extension until November 30, 2005 to ~~be submitted by September 30, 2005.~~review and update the stipulation.

~~In late July~~On August 8, 2005, the ~~House of Representatives and Senate passed~~President signed into law the Energy Policy Act of 2005 (the Act)~~, which was sent to the President for signing.~~. The Act ~~includes~~provides $14.5 billion in tax incentives over a 10-year period designed to ~~improve energy production, transmission and efficiency. Many of the tax incentives in the bill are geared towards boosting~~boost conservation efforts, increase domestic energy production ~~increasing conservation efforts,~~ and ~~developing~~expand the use of alternative energy sources, ~~of energy~~ such as solar, wind, ~~solar, bio-mass,~~ ethanol, biomass, hydropower and ~~clean-coal~~clean coal technology. The incentives include tax credits and shorter depreciable lives for many assets associated with energy production and transmission. ~~If enacted,~~The Act’s primary impact on HECO and its subsidiaries will be ~~impacted by~~ the reduction in the depreciable tax life, from 20 years to 15 years, ~~for~~of certain electric transmission equipment placed into service after ~~the effective date.~~April 11, 2005. Management ~~is analyzing~~continues to analyze the Act for further impacts.

The 2001 Hawaii Legislature adopted a law that required the utilities to meet a renewable portfolio standard (RPS). The 2004 Hawaii Legislature amended the RPS law to require electric utilities to meet a renewable portfolio standard of 8% by December 31, 2005, 10% by December 31, 2010, 15% by December 31, 2015, and 20% by December 31, 2020. The PUC has to determine if an electric utility is not able to meet the standard in a cost-effective manner or due to circumstances beyond its control. If such a determination is made, the utility is relieved of its responsibility to achieve the standard for that period of time. The PUC also may provide incentives to encourage electric utility companies to exceed their RPS or to meet their RPS ahead of time, or both.

The RPS law also directs the PUC, by December 31, 2006, to develop and implement a utility ratemaking structure, which may include, but is not limited to, performance-based ratemaking (PBR), to provide incentives that encourage Hawaii’s electric utility companies to use cost-effective renewable energy resources found in Hawaii to meet the RPS, while allowing for deviation from the standards in the event that the standards cannot be met in a cost-effective manner, or as a result of circumstances beyond the control of the utility which could not have been reasonably anticipated or ameliorated.

On November 1, 2004 the PUC transmitted an Initial Concept Paper, entitled “Electric Utility Rate Design in Hawaii,” describing the PUC’s intended methodology for fulfilling the legislative mandate. The overall process envisioned by the PUC is the conduct of three sets of workshops, and the creation of a document that forms the basis of a set of rules to be adopted in a conventional rulemaking process to follow, providing input to the PUC’s decisions on electric utility ratemaking. Management cannot predict the outcome of this process.

The goal of the first workshop was to describe and gather comments on the PUC’s methodology as a whole. The goal of the second workshop was to describe and gather comments on the key factors driving successful RPS

schemes and PBR regimes as well as on their use as inputs to the design of electric utility rates in Hawaii. The goal of the third workshop is to describe and gather comments on the simulation of the power market in Hawaii incorporating, as discussed in the prior workshops, the lessons learned on electric utility rate design under various RPS schemes and PBR regimes, as well as on its use as a tool for electric utility rate design in Hawaii.

The first set of workshops was held in November 2004. On July 26, 2005, the PUC transmitted a Second Concept Paper (SCP) authored by Economists Incorporated (EI), entitled “Proposals for Implementing Renewable Portfolio Standards in Hawaii.” The paper identified and described a number of incentive regulation (IR) mechanisms, including renewable energy credit trading, alternative compliance fees, penalties and positive incentives. On September 23, 2005, the PUC transmitted EI’s technical paper entitled “Planned Computer Simulations Facilitating the Analysis of Proposals for Implementing the Renewable Portfolio Standards Provision in Hawaii.” The second set of workshops was held in October 2005. The PUC received comments from HECO and other participants on the papers prior to, during and after the workshops, and other IR mechanisms were proposed. The PUC plans to hold the third set of workshops in January 2006.

The electric utilities and its unregulated subsidiary, Renewable Hawaii, Inc. continue to pursue a three-pronged renewable energy strategy: a) promote the development of cost-effective, commercially viable renewable energy projects, b) facilitate the integration of intermittent renewable energy resources, and c) encourage renewable energy research, development, and demonstration projects (e.g., photovoltaic energy and an electronic shock absorber for wind generation). They are also conducting integrated resource planning to evaluate the increased use of renewables within the electric utilities’ service territories.

Among the various ways that the electric utilities support renewable energy are solar water heating and heat pump programs and the negotiation and execution of purchased power contracts with nonutility generators using renewable sources (e.g., refuse-fired, geothermal, hydroelectric and wind turbine generating systems).

HECO filed and received a patent in February 2005 for an electronic shock absorber (ESA) that addresses power fluctuations from wind resources. An ESA demonstration system is expected to be installed later this year and tested into 2006. HECO has sought protection of intellectual property rights in its ESA technology, including a portfolio of U.S. and international patents and patent filings. HECO has an intellectual property license agreement with the party constructing the ESA demonstration system. Management cannot predict the amount of royalties from the sale of ESAs in the future.

See “Collective bargaining agreements” in Note 5 of HECO’s “Notes to ~~HECO’s~~ Consolidated Financial Statements.”

To evaluate the technical feasibility of the “Broadband over Power Line” (BPL) technology and its applications, HECO completed a small-scale trial of the BPL technology. Based on the favorable results of the trial, HECO will be proceeding with a pilot in an expanded residential/commercial area in Honolulu. BPL-enabled utility applications being evaluated include distribution system line monitoring, advanced remote metering, residential direct load control and monitoring of distribution substation equipment. Although its evaluation will be focused primarily on utility applications of BPL, HECO will also be evaluating broadband information services that might potentially be provided by other service providers. The pilot commenced in June 2005 and is expected to run through at least the ~~first~~second quarter of 2006.

In October 2004, the Federal Communications Commission (FCC) released a Report and Order that amended and adopted new rules for Access Broadband over Power Line systems (Access BPL) and stated that an FCC goal in developing the rules for Access BPL “are therefore to provide a framework that will both facilitate the rapid introduction and development of BPL systems and protect licensed radio services from harmful interference.” Currently, there are no PUC regulations for electric utility applications of BPL systems.

See Note 5 of HECO’s “Notes to ~~HECO’s~~ Consolidated Financial Statements.”

See Note 7 of HECO’s “Notes to ~~HECO’s~~ Consolidated Financial Statements.”

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


(in millions)	June 30, 2005				December 31, 2004				September 30, 2005				December 31, 2004
Short-term borrowings	$	123	6	%	$	89	4	%	$	125	6	%	$	89	4	%
Long-term debt		760	39			753	40			765	39			753	40
Preferred stock		34	2			34	2			34	2			34	2
Common stock equity		1,030	53			1,017	54			1,038	53			1,017	54

	$	1,947	100	%	$	1,893	100	%	$	1,962	100	%	$	1,893	100	%

As of ~~July~~October 31, 2005, the Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HECO securities were as follows:

The rating agencies use a combination of qualitative measures (i.e., assessment of business risk that incorporates an analysis of the qualitative factors such as management, competitive positioning, operations, markets and regulation) as well as quantitative measures (e.g., cash flow, debt, interest coverage and liquidity ratios) in determining the ratings of HECO securities. In April 2005, S&P affirmed its corporate credit ratings of HECO, but revised its outlook from stable to negative, citing HECO’s need for a rate increase, rising operating expenses and yet to be recovered investments. S&P’s ratings outlook “assesses the potential direction of a long-term credit rating over the intermediate term (typically six months to two years).” ~~The~~In response to the PUC’s interim rate decision for HECO, S&P stated “a final order that closely mirrors the interim ruling appears to be sufficient to lift key financial metrics to levels that are marginally suitable for Standard & Poor’s guideposts for the ‘BBB’ rating category.” However, S&P will maintain its negative outlook ~~was reflected in S&P’s full report on HECO dated May 31, 2005.~~until the PUC issues its final order. Moody’s maintains a stable outlook on HECO. In May 2005, S&P revised HECO’s business profile from ~~‘6’~~“6” to ~~‘5’~~“5”. S&P ranks business profiles from ~~‘1’~~“1” (strong) to ~~‘10’~~“10” (weak).

HECO periodically utilizes short-term debt, principally commercial paper, to support normal operations and for other temporary requirements. HECO also periodically borrows short-term from HEI for itself and on behalf of HELCO and MECO, and HECO may borrow from or loan to HELCO and MECO short-term. HECO had an average outstanding balance of commercial paper for the first ~~six~~nine months of 2005 of ~~$93~~$95 million and had ~~$123~~$112 million of commercial paper outstanding at ~~June~~September 30, 2005. HECO had $13 million of short-term borrowings from HEI at September 30, 2005. Management believes that if HECO’s commercial paper ratings were to be downgraded, they might not be able to sell commercial paper under current market conditions.

At ~~June~~September 30, 2005, HECO maintained bank lines of credit totaling ~~$150 million and signed an agreement on August 5, 2005 increasing its bank lines of credit by $30 million for a total of~~ $180 million with six different banks (all expiring in 2006). These lines of credit are principally maintained by HECO to support the issuance of commercial

paper, but also may be drawn for general corporate purposes. Accordingly, the lines of credit are available for short-term liquidity in the event a rating agency downgrade were to reduce or eliminate access to the commercial paper markets. None of HECO’s line of credit agreements contain clauses that would affect access to the lines by reason of a ratings downgrade, nor do they have broad “material adverse change” clauses that could affect access to the lines in the event of any material adverse event so long as any such event is timely disclosed. However, access to some or all of the lines could be restricted, or defaults under the lines could occur, if representations and warranties in the agreements, as permitted to be updated, are not true and correct at the time an advance is requested or if HECO is not in compliance with the covenants in such agreements. Management believes that it is not likely that any such restriction or default will occur. At ~~June~~September 30, 2005, the lines were ~~unused.~~undrawn. To the extent deemed necessary, HECO anticipates arranging similar lines of credit as existing lines of credit expire.

Operating activities provided ~~$63~~$125 million in net cash during the first ~~six~~nine months of 2005. Investing activities during the same period used net cash of ~~$77~~$131 million primarily for capital expenditures, net of contributions in aid of construction. Financing activities for the period provided net cash of ~~$16~~$8 million, primarily due to the ~~$41~~$48 million net increase in short term borrowings and long-term debt, partly offset by the payment of ~~$20~~$35 million in common and preferred dividends.

As of ~~June~~September 30, 2005, approximately $6$1 million of proceeds from the sale by the Department of Budget and Finance of the State of Hawaii of Series 2002A Special Purpose Revenue Bonds (SPRBs) issued for the benefit of HECO remain undrawn. In May 2005, up to $160 million of SPRBs ($100 million for HECO, $40 million for HELCO and $20 million for MECO) were authorized by the Hawaii legislature for issuance through June 30, 2010 to finance the electric utilities’ capital improvement projects.

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


	Three months ended June 30,					% change		Primary reason(s) for significant change		Three months ended September 30,					% change
(in thousands)	2005		2004					Primary reason(s) for significant change	2005			2004			% change		Primary reason(s) for significant change
Revenues	$	91,946	$	89,982		% change	2		Higher interest income (resulting from higher average balances and yields for loans, partly offset by the impact of lower average balances and yields for investments and mortgage-related securities), partly offset by lower fee income		$	97,431	$	90,296		8			Higher interest income (resulting primarily from higher average balances and yields for loans, partly offset by lower FHLB stock dividend)

Operating income		22,202		23,011		(4	)	Higher net interest income and lower general and administrative expenses (prior year includes $5 million of interest accrued on cumulative bank franchise taxes as a result of an adverse tax ruling, partly offset by higher compensation and consulting expenses), more than offset by the reversal of provision for loan losses in prior year and lower fee income			25,938		26,531		(2	)		Higher net interest income and fee income, more than offset by the reversal of allowance for loan losses in prior year and higher general and administrative expenses

Net income		13,552		(6,949	)	NM		Lower income taxes (prior year includes $21 million net charge for cumulative bank franchise taxes through March 31, 2004 as a result of an adverse tax ruling) and lower preferred stock dividends, partly offset by lower operating income			15,911		15,378		3			Lower preferred stock dividends, partly offset by lower operating income and higher income taxes


	Six months ended June 30,				% Change		Primary reason(s) for significant change		Nine months ended September 30,					%
(in thousands)	2005		2004				Primary reason(s) for significant change	2005			2004		Change		Primary reason(s) for significant change
Revenues	$	189,170	$	179,240	% Change	6		Higher interest income (resulting from higher average loans and mortgage-related securities balances and higher weighted-average yields on mortgage-related securities, partly offset by the impact of a lower average balance and yield for investments), partly offset by lower fee income		$	286,601	$	269,536		6		Higher interest income (resulting from higher average balances and yields for loans and mortgage-related securities, partly offset by lower FHLB stock dividend), partly offset by lower fee income

Operating income		51,155		49,119	4		Higher net interest income, partly offset by higher general and administrative expenses, lower reversal of provision for loan losses and fee income			77,093		75,650		2		Higher net interest income, partly offset by higher general and administrative expenses and lower reversal of allowance for loan losses and fee income

Net income		31,313		8,978	249		Lower income taxes (prior year includes $21 million net charge for cumulative bank franchise taxes through March 31, 2004 as a result of an adverse tax ruling), lower preferred stock dividends and higher operating income			47,224		24,356		94		Lower income taxes (prior year includes $21 million net charge for cumulative bank franchise taxes through March 31, 2004 as a result of an adverse tax ruling), lower preferred stock dividends and higher operating income

ASB’s results of operations for the second quarter of 2004 include a net charge of $24 million due to an adverse tax ruling as discussed in Note 4 of HEI’s “Notes to ~~HEI’s~~ Consolidated Financial Statements” under “ASB Realty Corporation.” The $24 million net charge included a net $21 million of cumulative bank franchise taxes through March 31, 2004, plus a net $3 million of interest (or gross interest of $5 million, which is included in general and administrative expenses). The following table presents a reconciliation of ASB’s net income to net income excluding the $24 million charge and including additional bank franchise taxes in prior periods as if ASB had not taken a dividends received deduction on income from its REIT subsidiary. Management believes the adjusted information below presents ASB’s net income on a more comparable basis for the periods shown. However, net income, including these adjustments, is not a presentation defined under GAAP and may not be comparable to other companies or more useful than the GAAP presentation included in HEI’s consolidated financial statements.


	Three months ended June 30,					Six months ended June 30,					Nine months ended September 30
(in thousands)	2005		2004			2005		2004			2005		2004
Net income (loss)	$	13,552	$	(6,949	)	$	31,313	$	8,978
Net income											$	47,224	$	24,356

Cumulative franchise tax and interest, net	$	—	$	23,955		$	—	$	23,955		$	—	$	23,955
Additional franchise taxes, net (if recorded in prior periods)		—		—			—		(634	)		—		(634	)

Total adjustments	$	—	$	23,955		$	—	$	23,321		$	—	$	23,321

Net income – as adjusted	$	13,552	$	17,006		$	31,313	$	32,299
Net income - as adjusted											$	47,224	$	47,677

Taking into account the adjustments in the table above, ASB’s net income would have decreased ~~20% and 3%~~1% for the ~~three months and six~~nine months ended ~~June~~September 30, 2005, ~~respectively,~~ compared to the same ~~periods~~period last year (see discussion below).

Earnings of ASB depend primarily on net interest income, which is the difference between interest earned on interest-earning assets and interest paid on interest-bearing liabilities. ASB’s loan volumes and yields are affected by market interest rates, competition, demand for financing, availability of funds and management’s responses to these factors. At ~~June~~September 30, 2005, ASB’s net loan portfolio mix consisted of ~~76%~~75% residential loans, 7% commercial real estate loans, 11% business loans and 7% consumer loans. At December 31, 2004, ASB’s net loan portfolio mix consisted of 74% residential loans, 9% commercial real estate loans, 10% business loans and 7% consumer loans. ASB’s mortgage-related securities portfolio consists primarily of shorter-duration assets and is affected by market interest rates and demand.

Deposits continue to be the largest source of funds and are affected by market interest rates, competition and management’s responses to these factors. Advances from the FHLB of Seattle and securities sold under agreements to repurchase continue to be significant sources of funds. At ~~June~~September 30, 2005, ASB’s costing liabilities consisted of ~~52%~~51% core deposits, ~~21%~~22% term certificates and 27% FHLB advances and other borrowings. At December 31, 2004, ASB’s costing liabilities consisted of 51% core deposits, 20% term certificates and 29% FHLB advances and other borrowings.

   Three months ended June 30
Six months ended June 30

($ in thousands)
   2005
   2004
   Change
2005
   2004
   Change

Loans receivable

Average balances¹
   $ 3,380,147    $ 3,094,905    $ 285,242 $ 3,329,720    $ 3,097,207    $ 232,513
Interest income²
   50,657    45,832    4,825 99,170    92,241    6,929
Weighted-average yield (%)
   5.99    5.92    0.07 5.96    5.96    —
Mortgage-related securities

Average balances
   $ 2,760,209    $ 2,772,060    $ (11,851 ) $ 2,819,906    $ 2,724,645    $ 95,261
Interest income
   26,636    27,559    (923 ) 60,464    54,636    5,828
Weighted-average yield (%)
   3.86    3.98    (0.12 ) 4.29    4.01    0.28
Investments³

Average balances
   $ 212,889    $ 239,594    $ (26,705 ) $ 200,316    $ 259,104    $ (58,788 )
Interest and dividend income
   887    1,665    (778 ) 1,922    3,413    (1,491 )
Weighted-average yield (%)
   1.65    2.78    (1.13 ) 1.92    2.64    (0.72 )
Total earning assets

Average balances
   $ 6,353,245    $ 6,106,559    $ 246,686 $ 6,349,942    $ 6,080,956    $ 268,986
Interest and dividend income
   78,180    75,056    3,124 161,556    150,290    11,266
Weighted-average yield (%)
   4.92    4.92    —   5.09    4.94    0.15
Deposit liabilities

Average balances
   $ 4,441,024    $ 4,068,047    $ 372,977 $ 4,381,144    $ 4,042,376    $ 338,768
Interest expense
   12,460    11,464    996 24,477    23,674    803
Weighted-average rate (%)
   1.13    1.13    —   1.13    1.17    (0.04 )
Borrowings

Average balances
   $ 1,701,908    $ 1,831,495    $ (129,587 ) $ 1,743,878    $ 1,824,227    $ (80,349 )
Interest expense
   16,893    15,578    1,315 34,641    31,321    3,320
Weighted-average rate (%)
   3.97    3.41    0.56 3.99    3.44    0.55
Total costing liabilities

Average balances
   $ 6,142,932    $ 5,899,542    $ 243,390 $ 6,125,022    $ 5,866,603    $ 258,419
Interest expense
   29,353    27,042    2,311 59,118    54,995    4,123
Weighted-average rate (%)
   1.91    1.84    0.07 1.94    1.88    0.06
Net average balance, net interest income and interest rate spread

Net average balance
   $ 210,313    $ 207,017    $ 3,296 $ 224,920    $ 214,353    $ 10,567
Net interest income
   48,827    48,014    813 102,438    95,295    7,143
Interest rate spread (%)
   3.01    3.08    (0.07 ) 3.15    3.06    0.09

Net interest income ~~before provision for loan losses~~ for the ~~second~~third quarter of 2005 increased by ~~$0.8~~$4.3 million, or 2%9%, from the same period in 2004. Interest rate spread ~~decreased~~increased from ~~3.08%~~3.09% for the ~~second~~third quarter of 2004 to ~~3.01%~~3.26% for the ~~second~~third quarter of 2005 as ASB’s ~~rate on costing liabilities increased while the~~ yield on earning assets ~~remained flat,~~increased faster than the increase in the rate on costing liabilities, primarily as a result of ~~the decline~~an increase in the yield on loans and mortgage-related ~~securities and the suspension of dividends on FHLB stock in the second quarter of 2005.~~securities. Interest income on loans receivable increased due to increased loan production and higher weighted-average yields on the loan portfolio. The residential and commercial real estate loan portfolios grew as a result of continued strength in the Hawaii real estate ~~market.~~market and the commercial loan portfolio grew as businesses in Hawaii have resumed borrowing to expand and make capital investments. Interest income on mortgage-related securities was ~~lower~~about the same despite a $131 million drop in average balances primarily due to the ~~downward~~upward adjustment to the amortized cost of the mortgage-related securities portfolio based on updated prepayment expectations resulting from ~~lower~~higher interest rates at

September 30, 2005 compared to June 30, 2005. The decrease in average balances was the result of ASB’s focus on its core lending businesses and less reliance on wholesale business. Interest income on investments decreased ~~due to the reinvestment~~as a result of ~~excess liquidity into loans rather than short-term investments and~~ no dividends on stock in the FHLB of ~~Seattle.~~Seattle for the quarter compared to dividends on such stock of $0.8 million in the same quarter of last year. Interest expense on deposit liabilities increased primarily due to a ~~$245~~$195 million increase in average core ~~deposits.~~deposits and $167 million increase in average term certificates. The increase in average deposit balances was due to the growth of the Hawaii deposit market and ASB’s execution of its strategic initiatives to transform to a full-service community bank. Interest expense on other borrowings increased due to the upward repricing of adjustable rate borrowings, partly offset by a decrease in the outstanding average ~~balance.~~balance resulting from ASB’s focus on its deposit business and less reliance on wholesale business.

As of ~~June~~September 30, 2005, delinquent and nonaccrual loans to total loans continued to trend downward to ~~0.25%~~0.22% (from 0.41% at December 31, 2004), a level well below historical norms. During the ~~second~~third quarter of 2005, the need to provision for additional loan growth was fully offset by the release of reserves on existing loans due to strong asset quality. This compares with a reversal of ~~provision~~allowance for loan losses of ~~$3.0~~$3.8 million for the ~~same period in the previous year.~~third quarter of 2004.

Other income for the ~~second~~third quarter of 2005 ~~decreased~~increased by ~~$1.2~~$0.3 million or 8%2%, compared to the same period in 2004 as a result of lower fee income on loans serviced for others and on other financial products. The lower fee income on loans serviced for others was due to the release of a valuation allowance on ASB’s mortgage servicing rights in 2004. ~~Lower income on other financial products was due to lower annuity sales and contingent property and casualty insurance commission income, partly offset by increases in debit card fee income.~~

General and administrative expenses for the ~~second~~third quarter of 2005 ~~decreased~~increased by ~~$2.5~~$1.4 million, or 6%4%, from the same period in 2004. Expenses for compensation ~~and consulting and other services~~ increased ~~$2.5~~$1.2 million as a result of SOX compliance and strategic initiatives, but were more than offset by $4.9 million less in interest on income taxes. Substantially all of the second quarter 2004 interest on income taxes was the interest accrued on cumulative bank franchise taxes through March 31, 2004 as a result of an adverse tax ruling.initiatives.

In the ~~second~~third quarter of 2005, ASB paid $1.4 million less preferred stock dividends primarily due to the redemption of $75 million of its preferred stock in December 2004. HEIDI concurrently reinvested the redemption proceeds as a capital contribution to ASB.

Net interest income ~~before provision for loan losses~~ for the first ~~six~~nine months of 2005 increased by ~~$7.1~~$11.5 million, or 7%8%, from the same period in 2004. Interest rate spread increased from ~~3.06%~~3.07% for the ~~six~~nine months ended ~~June~~September 30, 2004 to ~~3.15%~~3.18% for the ~~six~~nine months ended ~~June~~September 30, 2005 as ASB’s yield on earning assets increased faster than the rate on costing liabilities. Interest income on loans receivable increased primarily due to the larger residential and commercial real estate loan portfolios as a result of continued strength in the Hawaii real estate market. Interest income on mortgage-related securities increased due to prior year growth in the mortgage-related securities portfolio and the net upward adjustments to the amortized cost of the portfolio based on updated prepayment expectations. Interest income on investments decreased due to the reinvestment of excess liquidity into loans rather than short-term investments and lower dividends on stock in the FHLB of Seattle. Interest expense on deposit liabilities increased primarily due to a ~~$251~~$232 million increase in average core ~~deposits.~~deposits and $115 million in term certificates. Interest expense on other borrowings increased due to the upward repricing of adjustable rate borrowings, partly offset by a decrease in the outstanding average balance.

ASB recognized a $3.1 million reversal of ~~provision~~allowance for loan losses during the first ~~six~~nine months of 2005 primarily due to the reversal of a specific loan loss reserve on a large commercial loan, which was repaid on April 1, 2005. This compares with a reversal of ~~provision~~allowance for loan losses of ~~$4.6~~$8.4 million for the same period in the previous year. As of ~~June~~September 30, 2005, ASB’s allowance for loan losses was ~~0.92%~~0.91% of average loans outstanding, compared to 1.08% at December 31, 2004 and ~~1.25%~~1.11% at ~~June~~September 30, 2004.


Six months ended June 30	2005			2004
							Nine months ended September 30
(in thousands)							2005			2004
Allowance for loan losses, January 1	$	33,857		$	44,285		$	33,857		$	44,285
Recovery of loan losses		(3,100	)		(4,600	)
Reversal of allowance for loan losses								(3,100	)		(8,400	)
Net charge-offs		(119	)		(929	)		(58	)		(1,313	)

Allowance for loan losses, June 30	$	30,638		$	38,756
Allowance for loan losses, September 30							$	30,699		$	34,572

Other income for the ~~six~~nine months ended ~~June~~September 30, 2005 decreased by ~~$1.3~~$1.0 million or 5%2%, compared to the same period in 2004 as a result of lower annuity sales and ~~lower contingent property~~fee income on deposit liabilities and ~~casualty insurance commission income,~~gain on sale of loans, partly offset by ~~increases~~an increase in debit card ~~fee~~ income.

General and administrative expenses for the ~~six~~nine months ended ~~June~~September 30, 2005 increased by ~~$2.3~~$3.7 million, or 3%, from the same period in 2004 as a result of several factors, including increased compensation and ~~consulting~~services expenses and a reserve for interest related to income taxes as a result of a recent Internal Revenue Service examination, partly offset by prior year’s $5 million of interest accrued on cumulative bank franchise taxes ~~though~~through March 31, 2004 as a result of an adverse tax ruling.

In the first ~~six~~nine months of 2005, ASB paid ~~$2.7~~$4.1 million less preferred stock dividends due to the redemption of $75 million of its preferred stock in December 2004. HEIDI concurrently reinvested the redemption proceeds as a capital contribution to ASB.

Since December 31, 2004, the yield curve flattened as a result of higher short-term interest rates and lower long-term interest rates. The net impact of this flattening was to reduce the market value of mortgage-related securities and reduce stockholder’s equity through a balance sheet charge to AOCI. This reduction in the market value of mortgage-related securities did not result in a charge to net income as the impairments in the value of the securities were deemed to be temporary. At September 30, 2005, June 30, 2005, March 31, 2005 and December 31, 2004, the unrealized loss, net of tax benefits, on available-for-sale mortgage-related securities (including securities pledged for repurchase agreements) in AOCI was $27 million, $11 million, $36 million and $7 million, respectively.

In December 2004, the FHLB of Seattle signed an agreement with its regulator, the Federal Housing Finance Board (Finance Board), to adopt a business and capital plan to strengthen its risk management, capital structure and governance. As of ~~June~~September 30, 2005, ASB had an investment in FHLB of Seattle stock of $98 million. In the first ~~half~~nine months of 2005, ASB received a stock dividend with a par value of $0.4 million on its investment in FHLB of Seattle stock, compared to a stock dividend with a par value of ~~$1.9~~$2.7 million in the first ~~half of 2004, $0.8 million in the third quarter~~nine months of 2004 and nil in the fourth quarter of 2004.

In April 2005, the FHLB of Seattle delivered a proposed three-year business plan and capital management plan to the Finance Board, and issued a press release stating that it anticipates minimal to no dividends in the next few years while it implements its new business model. No dividends were received by ASB from the FHLB of Seattle during the second ~~quarter.~~or third quarters of 2005. Member access to the FHLB of Seattle funding and liquidity is expected to continue unimpeded during implementation of the three-year plan.


(in millions)	June 30, 2005		December 31, 2004		% change		September 30, 2005		December 31, 2004		% change
Total assets	$	6,817	$	6,767	1		$	6,901	$	6,767	2
Available-for-sale investment and mortgage-related securities		2,735		2,953	(7	)		2,743		2,953	(7	)
Held-to-maturity investment securities		98		97	—
Investment in FHLB of Seattle stock								98		97	—
Loans receivable, net		3,428		3,249	5			3,502		3,249	8
Deposit liabilities		4,453		4,296	4			4,552		4,296	6
Securities sold under agreements to repurchase		667		811	(18	)		681		811	(16	)
Advances from Federal Home Loan Bank		1,018		988	3			1,008		988	2

As of ~~June~~September 30, 2005, ASB was the third largest financial institution in Hawaii based on assets of ~~$6.8~~$6.9 billion and deposits of ~~$4.5~~$4.6 billion.

At ~~June~~September 30, 2005, ASB’s unused FHLB borrowing capacity was approximately $1.4 billion. At ~~June~~September 30, 2005, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of ~~$1.0~~$1.1 billion. Management believes ASB’s current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.

For the first ~~six~~nine months of 2005, net cash provided by ASB’s operating activities was ~~$12~~$24 million. Net cash ~~provided~~used by ASB’s investing activities was ~~$25~~$75 million, due to ~~the~~a net increase in loans receivable, partly offset by repayments and sales of mortgage-related securities, net of ~~purchases, partly offset by originations and purchases of loans, net of repayments.~~purchases. Net cash provided by financing activities was ~~$20~~$114 million due to net increases of ~~$157~~$256 million in deposit liabilities and ~~$30~~$20 million in advances from the FHLB of Seattle, partly offset by a net decrease of ~~$144~~$131 million in securities sold under agreements to repurchase and the payment of ~~$19~~$27 million in common stock dividends.

As of ~~June~~September 30, 2005, ASB was well-capitalized (ratio requirements noted in parentheses) with a leverage ratio of 7.2% (5.0%), a Tier-1 risk-based capital ratio of 14.2% (6.0%) and a total risk-based capital ratio of 15.0% (10.0%).

The Company’s results of operations and financial condition can be affected by numerous factors, many of which are beyond its control and could cause future results of operations to differ materially from historical results. For information about certain of these factors, see pages 77 to 85 of HEI’s 2004 Form 10-K.

Additional factors that may affect future results and financial condition are described on page iv under “Cautionary Statements and Risk Factors that May Affect Future Results.”

In accordance with SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” management has identified the accounting policies it believes to be the most critical to the Company’s financial statements—that is, management believes that these policies are both the most important to the portrayal of the Company’s financial condition and results of operations, and currently require management’s most difficult, subjective or complex judgments. For information about these policies, see pages 85 to 89 of HEI’s 2004 Form 10-K.

In preparing 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. In determining that HECO is not the primary beneficiary of Kalaeloa under the provisions of FIN 46R (see Notes 2 and 7 of HECO’s “Notes to Consolidated Financial Statements”), management used estimates in computing Kalaeloa’s expected cash flows. Estimates used in the analysis, for example with respect to the variability of fuel usage and pricing and operational levels and costs, are particularly susceptible to change. Management used its best efforts to determine the expected cash flows based on historical experience, financial information provided by Kalaeloa and on various other assumptions that were believed to be reasonable under the circumstances, the results of which formed the basis for the estimated cash flows. Actual results of Kalaeloa could differ significantly from those estimations.

The Company considers interest-rate risk (a non-trading market risk) to be a very significant market risk for ASB as it could potentially have a significant effect on the Company’s financial condition and results of operations. For additional quantitative and qualitative information about the Company’s market risks, see pages 90 to 93 of HEI’s 2004 Form 10-K.

ASB’s interest-rate risk sensitivity measures as of ~~June~~September 30, 2005 and December 31, 2004 ~~constitute “forward-looking statements” and~~ were as follows:


		June 30, 2005						December 31, 2004						September 30, 2005						December 31, 2004
		Change in net interest income (NII)		Net Portfolio value (NPV) Ratio		NPV ratio sensitivity (change from base case in basis points)		Change in NII		NPV ratio		NPV ratio sensitivity (change from base case in basis points)		Change in net interest income (NII)		Net portfolio value (NPV) ratio		NPV ratio sensitivity (change from base case in basis points)		Change in NII		NPV ratio		NPV ratio sensitivity (change from base case in basis points)
Change in interest rates (basis points)	Change in interest rates (basis points)
+300		(6.2	)%	8.33	%	(310	)	(7.7	)%	7.28	%	(367	)	(8.1	)%	8.16	%	(316	)	(7.7	)%	7.28	%	(367	)
+200		(4.1	)	9.57		(186	)	(5.0	)	8.69		(226	)	(5.6	)	9.35		(197	)	(5.0	)	8.69		(226	)
+100		(1.8	)	10.67		(76	)	(2.0	)	9.99		(96	)	(2.7	)	10.46		(86	)	(2.0	)	9.99		(96	)
Base		—		11.43		—		—		10.95		—		—		11.32		—		—		10.95		—
-100		(2.7	)	11.51		8		(3.9	)	11.22		27		1.1		11.64		32		(3.9	)	11.22		27

Management believes that ASB’s interest rate risk position at ~~June~~September 30, 2005 represents a reasonable level of risk. The bank’s NII profile as of ~~June~~September 30, 2005 is slightly ~~less~~more sensitive to changes in interest rates compared to the NII profile on December 31, 2004. This change is primarily due to ~~a shift~~smaller changes in ~~liability mix. Growth~~prepayment estimates for the mortgage assets and mortgage-related securities in ~~deposits during~~ the ~~period enabled the bank to replace maturing wholesale borrowings with deposits, which helped to reduce the bank’s NII sensitivity.~~alternate interest rate scenarios as of September 30, 2005.

ASB’s base NPV ratio as of ~~June~~September 30, 2005 was higher compared to December 31, 2004. ~~The shift~~Growth in ~~liability mix~~deposits during the period contributed to the ~~increase.~~increase, as ASB was able to replace higher-cost wholesale borrowings with deposits. Core deposits are the lowest cost funding source available to ~~the bank,~~ASB, so increasing the level of core deposits, relative to wholesale liabilities, ~~will cause~~causes the NPV ratio to increase.

ASB’s NPV ratio sensitivity measures as of ~~June~~September 30, 2005 were lower than the sensitivity measures as of December 31, 2004. The decrease was due to several factors including the increase in deposit balances as well as the ~~lower~~faster overall level of ~~long-term interest rates, which resulted in faster~~expected prepayment ~~expectations~~speeds, and correspondingly shorter expected average lives, for the mortgage assets and mortgage-related securities.

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

HEI: Robert F. Clarke, HEI Chief Executive Officer, and Eric K. Yeaman, HEI Chief Financial Officer, have evaluated the disclosure controls and procedures of HEI as of ~~June~~September 30, 2005. Based on their evaluations, as of ~~June~~September 30, 2005, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective.

HECO: T. Michael May, HECO Chief Executive Officer, and Tayne S. Y. Sekimura, HECO Chief Financial Officer, have evaluated the disclosure controls and procedures of HECO as of ~~June~~September 30, 2005. Based on their evaluations, as of ~~June~~September 30, 2005, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective.

There are no significant developments in pending legal proceedings except as set forth in HEI’s and HECO’s “Notes to Consolidated Financial Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” With regard to any pending legal proceeding, alternative dispute resolution, such as mediation or settlement, may be pursued where appropriate, with such efforts typically maintained in confidence unless and until a resolution is achieved.

(a) For the six months ended June 30, 2005, HEI issued an aggregate of 28,200 shares of unregistered common stock pursuant to the HEI 1990 Nonemployee Director Stock Plan, as amended and restated effective March 8, 2005 (the HEI Nonemployee Director Plan). Under the HEI Nonemployee Director Plan, each HEI nonemployee director receives, in addition to an annual cash retainer, an annual stock grant of 1,400 sharesPurchases of HEI common ~~stock (2,000~~ shares for the first time grant to a new HEI director) and each nonemployee subsidiary director who is not also an HEI nonemployee director receives an annual stock grant of 1,000 shares of HEI common stock (600 shares for the first time grant to a new subsidiary director). The HEI Nonemployee Director Plan is currently the only plan for nonemployee directors and provides for annual stock grants (described above) and annual cash retainers for nonemployee directors of HEI and its subsidiaries.

~~HEI did not register the shares issued under the director stock plan since their issuance did not involve a “sale”~~were made as defined under Section 2(3) of the Securities Act of 1933, as amended. Participation by nonemployee directors of HEI and subsidiaries in the director stock plans is mandatory and thus does not involve an investment decision.follows:


	Six months ended June 30, 2005		Years ended December 31,									Nine months ended September 30, 2005		Years ended December 31,
		2004		2003		2002		2001		2000		Nine months ended September 30, 2005	2004		2003		2002		2001		2000
HEI and Subsidiaries	Six months ended June 30, 2005
Excluding interest on ASB deposits	2.07		2.32		2.11		2.03		1.82		1.76	2.23		2.32		2.11		2.03		1.82		1.76
Including interest on ASB deposits	1.81		2.00		1.84		1.72		1.52		1.49	1.93		2.00		1.84		1.72		1.52		1.49
HECO and Subsidiaries	3.00		3.49		3.36		3.71		3.51		3.39	3.24		3.49		3.36		3.71		3.51		3.39

At its meeting on April 26, 2005, the Board of Directors of HEI rescinded its policy that the fourth quarter installment of the annual board retainer would be withheld from nonemployee directors who did not attend at least 75% of the combined total of all Board meetings and all meetings of the Board committees on which they serve.

In 2004, there were nine regular and two special meetings of the Board of Directors. All directors, except one, attended at least 75% of the 2004 combined total meetings of the Board and Board committees on which they served (during the periods they served). The one director who did not meet this requirement was Don E. Carroll, who attended 72% of his combined total meetings. In rescinding its previous policy, the Board also approved payment to Mr. Carroll of the fourth installment of his nonemployee director’s fee. Mr. Carroll’s attendance record for 2004 was disclosed in the March 31, 2005 proxy statement, as required by Rule 14a-101 under the Securities Exchange Act of 1934. This disclosure requirement was deemed by the Board to be sufficient inducement for directors to attend meetings.

~~HEI’s other policies for compensation of directors for their service are as disclosed in HEI’s proxy statement for the 2005 Annual Meeting.~~

In December 2002, HECO formed an unregulated subsidiary, RHI, with initial approval to invest up to $10 million in selected renewable energy projects. RHI is seeking to stimulate renewable energy initiatives by prospecting for new projects and sites and taking a passive, minority interest in third party renewable energy projects greater than 1 MW in Hawaii. Since 2003, RHI has periodically solicited competitive proposals for investment opportunities in qualified projects. To date, RHI has signed ~~a Conditional Investment Agreement~~conditional investment agreements for a municipal solid waste-to-energy project and ~~a Memorandum of Understanding for~~ a small-scale landfill gas-to-energy project, both on Oahu. A number of new proposals are currently being evaluated. Project investments by RHI will generally be made only after developers secure the necessary approvals and permits and independently execute a PPA with HECO, HELCO or MECO, approved by the PUC.

In July 2005, HECO held a series of community meetings to get feedback on a potential wind energy ~~project. HECO is evaluating the possibility of a wind farm~~project on the mountain ridges above its Kahe power ~~plant, assuming surrounding~~plant. In September 2005, after considering community ~~concerns can be satisfactorily addressed.~~feedback and opposition to the location of the project by the Mayor of the City and County of Honolulu, who declared that the wind farm would not receive the City permits necessary to operate, HECO decided not to pursue the project. HECO plans to review other potential sites for a wind energy project.

MECO has a PPA with Hawaiian Commercial & Sugar Company (HC&S) for 16 MW of firm capacity. On July 15, 2005, MECO and HC&S agreed that neither party will give written notice of termination under the terms of the PPA so as to cause the PPA to terminate prior to December 31, 2011. As a result, the PPA continues to remain in full force and effect through December 31, 2011, and from year to year thereafter, subject to termination on or after December 31, 2011 on not less than two years’ prior written notice by either party. Management expects the agreement will not result in consolidation in accordance with FIN 46R as HC&S continues to be a “business” as defined in the standard and not a VIE, and is thus excluded from the scope of FIN 46R. Additionally, management believes that the agreement would not require a reassessment under EITF Issue No. 01-8. However, if such reassessment were required, management does not believe that the PPA would meet the criteria under EITF Issue No. 01-8, which would result in the classification of the agreement as a lease.

In July 2005, HECO executed a new lease for its downtown office building. The term of the lease is from July 1, 2005 through November 30, 2021 with fixed monthly rent throughout. Rental payments through November 30, 2009 are $775,000 annually (the same amount as the previous lease just prior to expiration), and the lease contains fixed rent escalations of 10% every five years thereafter. The lease also grants HECO a three year extension option at a rent to be negotiated by the parties.

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


Exact Name of Registrant as Specified in Its Charter	Commission File Number	I.R.S. Employer Identification No.
HAWAIIAN ELECTRIC INDUSTRIES, INC.	1-8503	99-0208097

			and Principal Subsidiary

HAWAIIAN ELECTRIC COMPANY, INC.	1-4955	99-0040500


Class of Common Stock		Outstanding ~~August 1,~~October 31, 2005
Hawaiian Electric Industries, Inc. (Without Par Value)		~~80,934,009~~80,955,756 Shares
Hawaiian Electric Company, Inc. ($6-2/3 Par Value)		12,805,843 Shares (not publicly traded)


		Page No.
Glossary of Terms		ii
Cautionary Statements and Risk Factors that May Affect Future Results		iv

	PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements

	Hawaiian Electric Industries, Inc. and Subsidiaries

	Consolidated Balance Sheets (unaudited) - ~~June~~September 30, 2005 and December 31, 2004	1

	Consolidated Statements of Income (unaudited) - three and ~~six~~nine months ended ~~June~~September 30, 2005 and 2004	2

	Consolidated Statements of Changes in Stockholders’ Equity (unaudited) - ~~six~~nine months ended ~~June~~September 30, 2005 and 2004	3

	Consolidated Statements of Cash Flows (unaudited) - ~~six~~nine months ended ~~June~~September 30, 2005 and 2004	4

	Notes to Consolidated Financial Statements (unaudited)	5

	Hawaiian Electric Company, Inc. and Subsidiaries

	Consolidated Balance Sheets (unaudited) - ~~June~~September 30, 2005 and December 31, 2004	13

	Consolidated Statements of Income (unaudited) - three and ~~six~~nine months ended ~~June~~September 30, 2005 and 2004	14

	Consolidated Statements of Retained Earnings (unaudited) - three and ~~six~~nine months ended ~~June~~September 30, 2005 and 2004	14

	Consolidated Statements of Cash Flows (unaudited) - ~~six~~nine months ended ~~June~~September 30, 2005 and 2004	15

	Notes to Consolidated Financial Statements (unaudited)	16

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3233

	HEI Consolidated	33

	Electric Utilities	40

	~~HEI Consolidated~~Bank	3250

	~~Electric Utilities~~	37
	~~Bank~~	45
	Certain Factors that May Affect Future Results and Financial Condition	5055

	Material Estimates and Critical Accounting Policies	5055

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	5056

Item 4.	Controls and Procedures	5157

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	5157

Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	5157

Item 5.	Other Information	5258

Item 6.	Exhibits	5459

Signatures		5560


	S&P	Moody’s
Commercial paper	A-2	P-2
Revenue bonds (senior unsecured, insured)	AAA	Aaa
HECO-obligated preferred securities of trust subsidiaries	BBB-	Baa2
Cumulative preferred stock (selected series)	NRNot rated	Baa3


Terms		Definitions
AES Hawaii		AES Hawaii, Inc., formerly known as AES Barbers Point, Inc.

AFUDC		Allowance for funds used during construction

AOCI		Accumulated other comprehensive income

ASB		American Savings Bank, F.S.B., a wholly-owned subsidiary of HEI Diversified, Inc. and parent company of American Savings Investment Services Corp. (and its subsidiary, Bishop Insurance Agency of Hawaii, Inc.) and AdCommunications, Inc. Former subsidiaries include ASB Realty Corporation (dissolved in May 2005) and ASB Service Corporation (dissolved in January 2004).

BLNR		Board of Land and Natural Resources of the State of Hawaii

CHP		Combined heat and power

Company		Hawaiian Electric Industries, Inc. and its direct and indirect subsidiaries, including, without limitation, Hawaiian Electric Company, Inc., Maui Electric Company, Limited, Hawaii Electric Light Company, Inc., HECO Capital Trust III, Renewable Hawaii, Inc., HEI Diversified, Inc., American Savings Bank, F.S.B. and its subsidiaries, Pacific Energy Conservation Services, Inc., HEI Properties, Inc., Hycap Management, Inc. (in dissolution), Hawaiian Electric Industries Capital Trust II, Hawaiian Electric Industries Capital Trust III, The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.) and HEI Power Corp. and its subsidiaries (discontinued operations, except for subsidiary HEI Investments, Inc.). Former subsidiaries include HECO Capital Trust I (dissolved in April 2004 and terminated in December 2004), HECO Capital Trust II (dissolved in April 2004 and terminated in December 2004), Hawaiian Electric Industries Capital Trust I (dissolved in April 2004 and terminated in December 2004), HEI Preferred Funding, LP (dissolved in April 2004 and terminated in December 2004)* and Malama Pacific Corp. (discontinued operations, dissolved in June 2004). (*unconsolidated subsidiaries as of January 1, 2004)

Consumer Advocate		Division of Consumer Advocacy, Department of Commerce and Consumer Affairs of the State of Hawaii

D&O		Decision and order

DG		Distributed generation

DOD		Department of Defense — federal

DOH		Department of Health of the State of Hawaii

DOT		Department of Taxation of the State of Hawaii

DRIP		HEI Dividend Reinvestment and Stock Purchase Plan

DSM		Demand-side management

EITF		Emerging Issues Task Force

EPA		Environmental Protection Agency — federal

FASB		Financial Accounting Standards Board

Federal		U.S. Government

FHLB		Federal Home Loan Bank

FIN		Financial Accounting Standards Board Interpretation No.

GAAP		Accounting principles generally accepted in the United States of America

HECO		Hawaiian Electric Company, Inc., an electric utility subsidiary of Hawaiian Electric Industries, Inc. and parent company of Maui Electric Company, Limited, Hawaii Electric Light Company, Inc., HECO Capital Trust III* and Renewable Hawaii, Inc. Former subsidiaries include HECO Capital Trust I (dissolved in April 2004 and terminated in December 2004)* and HECO Capital Trust II (dissolved in April 2004 and terminated in December 2004). (unconsolidated subsidiaries as of January 1, 2004)


Terms		Definitions
HEI		Hawaiian Electric Industries, Inc., direct parent company of Hawaiian Electric Company, Inc., HEI Diversified, Inc., Pacific Energy Conservation Services, Inc., HEI Properties, Inc., Hycap Management, Inc. (in dissolution), Hawaiian Electric Industries Capital Trust II, Hawaiian Electric Industries Capital Trust III, The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.) and HEI Power Corp. (discontinued operations, except for subsidiary HEI Investments, Inc.). Former subsidiaries include Hawaiian Electric Industries Capital Trust I (dissolved in April 2004 and terminated in December 2004)* and Malama Pacific Corp. (discontinued operations, dissolved in June 2004). (*unconsolidated subsidiaries as of January 1, 2004)

HEIDI		HEI Diversified, Inc., a wholly owned subsidiary of Hawaiian Electric Industries, Inc. and the parent company of American Savings Bank, F.S.B.

HEIII		HEI Investments, Inc. (formerly HEI Investment Corp.), a subsidiary of HEI Power Corp.

HEIPC		HEI Power Corp., a wholly owned subsidiary of Hawaiian Electric Industries, Inc., and the parent company of numerous subsidiaries, several of which were dissolved or otherwise wound up in 2002, 2003 and 2004, pursuant to a formal plan to exit the international power business (formerly engaged in by HEIPC and its subsidiaries) adopted by the HEI Board of Directors in October 2001

HEIPC Group		HEI Power Corp. and its subsidiaries

HEIRSP		Hawaiian Electric Industries Retirement Savings Plan

HELCO		Hawaii Electric Light Company, Inc., an electric utility subsidiary of Hawaiian Electric Company, Inc.

HTB		Hawaiian Tug & Barge Corp. In November 1999, HTB sold substantially all of its operating assets and the stock of Young Brothers, Limited, and changed its name to The Old Oahu Tug Services, Inc.

IPP		Independent power producer

IRP		Integrated resource plan

KWH		Kilowatthour

MECO		Maui Electric Company, Limited, an electric utility subsidiary of Hawaiian Electric Company, Inc.

MW		Megawatt/s (as applicable)

NII		Net interest income

NPV		Net portfolio value

PPA		Power purchase agreement

PRPs		Potentially responsible parties

PUC		Public Utilities Commission of the State of Hawaii

REIT		Real estate investment trust

RHI		Renewable Hawaii, Inc., a wholly owned subsidiary of Hawaiian Electric Company, Inc.

ROACE		Return on average common equity

ROR		Return on average rate base

SEC		Securities and Exchange Commission

See		Means the referenced material is incorporated by reference

SFAS		Statement of Financial Accounting Standards

SOX		Sarbanes-Oxley Act of 2002

SPRBs		Special Purpose Revenue Bonds

TOOTS		The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.), a wholly owned subsidiary of Hawaiian Electric Industries, Inc. On November 10, 1999, HTB sold the stock of YB and substantially all of HTB’s operating assets and changed its name.

VIE		Variable interest entity

YB		Young Brothers, Limited, which was sold on November 10, 1999, was formerly a wholly owned subsidiary of Hawaiian Tug & Barge Corp.


	Discount rate
($ in millions)	5.50%		6.00%
Consolidated HEI
0% return on plan asset assumption	$	109	$	82
9% return on plan asset assumption		70		1

Consolidated HECO
0% return on plan asset assumption	$	106	$	80
9% return on plan asset assumption		68		—

ASB
0% return on plan asset assumption	$	—	$	—
9% return on plan asset assumption		—		—


	Three months ended June 30							Six months ended June 30
($ in thousands)	2005		2004		Change			2005		2004		Change
Loans receivable
Average balances¹	$	3,380,147	$	3,094,905	$	285,242		$	3,329,720	$	3,097,207	$	232,513
Interest income²		50,657		45,832		4,825			99,170		92,241		6,929
Weighted-average yield (%)		5.99		5.92		0.07			5.96		5.96		—

Mortgage-related securities
Average balances	$	2,760,209	$	2,772,060	$	(11,851	)	$	2,819,906	$	2,724,645	$	95,261
Interest income		26,636		27,559		(923	)		60,464		54,636		5,828
Weighted-average yield (%)		3.86		3.98		(0.12	)		4.29		4.01		0.28

Investments³
Average balances	$	212,889	$	239,594	$	(26,705	)	$	200,316	$	259,104	$	(58,788	)
Interest and dividend income		887		1,665		(778	)		1,922		3,413		(1,491	)
Weighted-average yield (%)		1.65		2.78		(1.13	)		1.92		2.64		(0.72	)

Total earning assets
Average balances	$	6,353,245	$	6,106,559	$	246,686		$	6,349,942	$	6,080,956	$	268,986
Interest and dividend income		78,180		75,056		3,124			161,556		150,290		11,266
Weighted-average yield (%)		4.92		4.92		—			5.09		4.94		0.15

Deposit liabilities
Average balances	$	4,441,024	$	4,068,047	$	372,977		$	4,381,144	$	4,042,376	$	338,768
Interest expense		12,460		11,464		996			24,477		23,674		803
Weighted-average rate (%)		1.13		1.13		—			1.13		1.17		(0.04	)

Borrowings
Average balances	$	1,701,908	$	1,831,495	$	(129,587	)	$	1,743,878	$	1,824,227	$	(80,349	)
Interest expense		16,893		15,578		1,315			34,641		31,321		3,320
Weighted-average rate (%)		3.97		3.41		0.56			3.99		3.44		0.55

Total costing liabilities
Average balances	$	6,142,932	$	5,899,542	$	243,390		$	6,125,022	$	5,866,603	$	258,419
Interest expense		29,353		27,042		2,311			59,118		54,995		4,123
Weighted-average rate (%)		1.91		1.84		0.07			1.94		1.88		0.06

Net average balance, net interest income and interest rate spread
Net average balance	$	210,313	$	207,017	$	3,296		$	224,920	$	214,353	$	10,567
Net interest income		48,827		48,014		813			102,438		95,295		7,143
Interest rate spread (%)		3.01		3.08		(0.07	)		3.15		3.06		0.09


Period*	(a) Total Number of Shares Purchased **	(b) Average Price Paid per Share **		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs **	(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
April 1 to 30, 2005	49,084	$	25.59	—	NA
May 1 to 31, 2005	115,673		25.42	—	NA
June 1 to 30, 2005	280,927		26.59	—	NA

	445,684	$	26.18	—	NA


~~HEI~~ ~~Exhibit 10.1~~		~~Form of Hawaiian Electric Industries, Inc. Stock Appreciation Right Agreement with Dividend Equivalents (effective for April 7, 2005 stock appreciation rights grant)~~

~~HEI~~ ~~Exhibit 10.2~~		~~Form of Restricted Stock Agreement Pursuant to the 1987 Stock Option and Incentive Plan of Hawaiian Electric Industries, Inc.~~

~~HEI~~ ~~Exhibit 10.3~~		~~Nonemployee Director’s Compensation Schedule as of April 1, 2005~~

HEI Exhibit 12.1		Hawaiian Electric Industries, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, ~~six~~nine months ended ~~June~~September 30, 2005 and 2004 and years ended December 31, 2004, 2003, 2002, 2001 and 2000

HEI Exhibit 31.1		Certification Pursuant to Section 13a-14 of the Securities Exchange Act of 1934 of Robert F. Clarke (HEI Chief Executive Officer)

HEI Exhibit 31.2		Certification Pursuant to Section 13a-14 of the Securities Exchange Act of 1934 of Eric K. Yeaman (HEI Chief Financial Officer)

HEI Exhibit 32.1		Written Statement of Robert F. Clarke (HEI Chief Executive Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002

HEI Exhibit 32.2		Written Statement of Eric K. Yeaman (HEI Chief Financial Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002

~~HEI~~ ~~Exhibit 99.1~~		~~Amendment 2005-1 to the Hawaiian Electric Industries Retirement Savings Plan, executed June 16, 2005~~

HECO Exhibit 12.2		Hawaiian Electric Company, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, ~~six~~nine months ended ~~June~~September 30, 2005 and 2004 and years ended December 31, 2004, 2003, 2002, 2001 and 2000

HECO Exhibit 31.3		Certification Pursuant to Section 13a-14 of the Securities Exchange Act of 1934 of T. Michael May (HECO Chief Executive Officer)

HECO Exhibit 31.4		Certification Pursuant to Section 13a-14 of the Securities Exchange Act of 1934 of Tayne S. Y. Sekimura (HECO Chief Financial Officer)

HECO Exhibit 32.3		Written Statement of T. Michael May (HECO Chief Executive Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002

HECO Exhibit 32.4		Written Statement of Tayne S. Y. Sekimura (HECO Chief Financial Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002


HAWAIIAN ELECTRIC INDUSTRIES, INC.		HAWAIIAN ELECTRIC COMPANY, INC.
(Registrant)		(Registrant)

By	/s/ Robert F. Clarke	By	/s/ T. Michael May
	Robert F. Clarke		T. Michael May
	Chairman, President and Chief Executive Officer (Principal Executive Officer of HEI)		President and Chief Executive Officer
	~~(Principal Executive Officer of HEI)~~		(Principal Executive Officer of HECO)

By	/s/ Eric K. Yeaman	By	/s/ Tayne S. Y. Sekimura
	Eric K. Yeaman		Tayne S. Y. Sekimura
	Financial Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer of HEI)		Financial Vice President (Principal Financial Officer of HECO)
	~~(Principal Financial Officer of HEI)~~

By	/s/ Curtis Y. Harada	By	/s/ Patsy H. Nanbu
	Curtis Y. Harada		Patsy H. Nanbu
	Controller		~~Controller~~
	(Chief Accounting Officer of HEI)		Controller (Chief Accounting Officer of HECO)

Date: ~~August 5,~~November 9, 2005		Date: ~~August 5,~~November 9, 2005