Edgar Filing: HAWAIIAN ELECTRIC INDUSTRIES INC

FORM 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2006

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


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

State of Hawaii

(State or other jurisdiction of incorporation or organization)

900 Richards Street, Honolulu, Hawaii 96813

(Address of principal executive offices and zip code)

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

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

(Registrant’s telephone number, including area code)

Not applicable

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

Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc. (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 the 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 Company, Inc. (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 the 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 a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act).


Large accelerated filer x		Accelerated filer ¨		Non-accelerated filer ¨

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act).


Large accelerated filer ¨		Accelerated filer ¨		Non-accelerated filer 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

APPLICABLE ONLY TO CORPORATE ISSUERS:

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


Class of Common Stock		Outstanding July 27, 2006
Hawaiian Electric Industries, Inc. (Without Par Value)		81,284,371 Shares
Hawaiian Electric Company, Inc. ($6-2/3 Par Value)		12,805,843 Shares (not publicly traded)

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended June 30, 2006

INDEX


		Page No.
Glossary of Terms		ii
Forward-Looking Statements		iv

PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements
	Hawaiian Electric Industries, Inc. and Subsidiaries
	Consolidated Balance Sheets (unaudited) - June 30, 2006 and December 31, 2005	1
	Consolidated Statements of Income (unaudited) - three and six months ended June 30, 2006 and 2005	2
	Consolidated Statements of Changes in Stockholders’ Equity (unaudited) - six months ended June 30, 2006 and 2005	3
	Consolidated Statements of Cash Flows (unaudited) - six months ended June 30, 2006 and 2005	4
	Notes to Consolidated Financial Statements (unaudited)	5

	Hawaiian Electric Company, Inc. and Subsidiaries
	Consolidated Balance Sheets (unaudited) - June 30, 2006 and December 31, 2005	15
	Consolidated Statements of Income (unaudited) - three and six months ended June 30, 2006 and 2005	16
	Consolidated Statements of Retained Earnings (unaudited) - three and six months ended June 30, 2006 and 2005	16
	Consolidated Statements of Cash Flows (unaudited) - six months ended June 30, 2006 and 2005	17
	Notes to Consolidated Financial Statements (unaudited)	18

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
	HEI Consolidated	36
	Electric Utilities	42
	Bank	57
	Certain Factors that May Affect Future Results and Financial Condition	61
	Material Estimates and Critical Accounting Policies	62

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	62

Item 4.	Controls and Procedures	63

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	64

Item 1A.	Risk Factors	64

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	66

Item 4.	Submission of Matters to a Vote of Security Holders	67

Item 5.	Other Information	68

Item 6.	Exhibits	69

Signatures		70

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended June 30, 2006

GLOSSARY OF TERMS


Terms		Definitions
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).
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. and HEI Power Corp. and its subsidiaries (discontinued operations, except for subsidiary HEI Investments, Inc.). (unconsolidated subsidiaries)
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
DRIP		HEI Dividend Reinvestment and Stock Purchase Plan
DSM		Demand-side management
EPA		Environmental Protection Agency — federal
Exchange Act		Securities Exchange Act of 1934
FASB		Financial Accounting Standards Board
Federal		U.S. Government
FHLB		Federal Home Loan Bank
FIN		Financial Accounting Standards Board Interpretation
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 (unconsolidated subsidiary) and Renewable Hawaii, Inc.

GLOSSARY OF TERMS, continued


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. and HEI Power Corp. (discontinued operations, except for subsidiary HEI Investments, Inc.). (*unconsolidated subsidiaries)
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, the majority of which were dissolved or otherwise wound up since 2002, 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.
HPower		City and County of Honolulu with respect to a power purchase agreement for a refuse-fired plant
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
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
SOIP		1987 Stock Option and Incentive Plan, as amended
SOX		Sarbanes-Oxley Act of 2002
SPRBs		Special Purpose Revenue Bonds
TOOTS		The Old Oahu Tug Service, a wholly owned subsidiary of Hawaiian Electric Industries, Inc.
VIE		Variable interest entity

iii

Forward-Looking Statements

This report and other presentations made by Hawaiian Electric Industries, Inc. (HEI) and Hawaiian Electric Company, Inc. (HECO) and their subsidiaries contain “forward-looking statements,” which include statements that are predictive in nature, depend upon or refer to future events or conditions, and usually include words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “predicts,” “estimates” or similar expressions. In addition, any statements concerning future financial performance, 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:

•

the effects of international, national and local economic conditions, including the state of the Hawaii tourist and construction industries, the strength or weakness of the Hawaii and continental U.S. real estate markets (including the fair value of collateral underlying loans and mortgage-related securities) and decisions concerning the extent of the presence of the federal government and military in Hawaii;

•

the effects of weather and natural disasters;

•

global developments, including the effects of terrorist acts, the war on terrorism, continuing U.S. presence in Iraq and Afghanistan, potential conflict or crisis with North Korea and in the Middle East, relations with Iran, Iran’s nuclear activities and potential avian flu pandemic;

•

the timing and extent of changes in interest rates and the shape of the yield curve;

•

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

•

changes in assumptions used to calculate retirement benefits costs and changes in funding requirements, including those resulting from final adoption of proposed pension reform legislation;

•

increasing competition in the electric utility and banking industries (e.g., increased self-generation of electricity may have an adverse impact on HECO’s revenues and increased price competition for deposits, or an outflow of deposits to alternative investments, may have an adverse impact on American Savings Bank, F.S.B.’s (ASB’s) cost of funds);

•

capacity and supply constraints or difficulties, especially if generating units (utility-owned or independent power producer (IPP)-owned) fail or measures such as demand-side management (DSM), distributed generation (DG), combined heat and power (CHP) or other firm capacity supply-side resources fall short of achieving their forecasted benefits or are otherwise insufficient to reduce or meet peak demand;

•

increased risk to generation reliability as generation reserve margins on Oahu are lower than considered desirable;

•

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

•

the ability of IPPs to deliver the firm capacity anticipated in their power purchase agreements (PPAs);

•

the ability of the electric utilities to negotiate, periodically, favorable fuel supply and collective bargaining agreements;

•

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

•

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

•

increasing operations and maintenance expenses for the electric utilities and the possibility of more frequent rate cases;

•

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

•

the effects of changes in accounting principles applicable to HEI, HECO and their subsidiaries, including the adoption of new accounting principles (such as the effects of proposed changes in the accounting for retirement benefits, if and when effective), continued regulatory accounting under Statement of Financial Accounting Standards (SFAS) No. 71 (Accounting for the Effects of Certain Types of Regulation), and the possible effects of applying Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46R (Consolidation of Variable Interest Entities) and Emerging Issues Task Force Issue No. 01-8 (Determining Whether an Arrangement Contains a Lease) to power purchase arrangements with independent power producers;

•

the effects of changes by securities rating agencies in their ratings of the securities of HEI and HECO and the results of financing efforts;

•

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

•

changes in ASB’s loan portfolio credit profile and asset quality which may increase or decrease the required level of allowance for loan losses;

•

changes in ASB’s deposit mix which may have an adverse impact on ASB’s cost of funds;

•

the final outcome of tax positions taken by HEI, HECO and their subsidiaries;

•

the ability of consolidated HEI to generate capital gains and utilize capital loss carryforwards on future tax returns;

•

the risks of suffering losses and incurring liabilities that are uninsured; and

•

other risks or uncertainties described elsewhere in this report and in other periodic reports (e.g., “Item 1A. Risk Factors” in the Company’s Annual Report on Form 10-K) previously and subsequently filed by HEI and/or HECO with the Securities and Exchange Commission (SEC).

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

PART I - FINANCIAL INFORMATION

Item 1.

Financial Statements

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)


(dollars in thousands)	June 30, 2006			December 31, 2005
Assets
Cash and equivalents	$	144,945		$	151,513
Federal funds sold		81,121			57,434
Accounts receivable and unbilled revenues, net		247,817			249,473
Available-for-sale investment and mortgage-related securities		2,506,444			2,629,351
Investment in stock of Federal Home Loan Bank of Seattle, at cost		97,764			97,764
Loans receivable, net		3,717,501			3,566,834
Property, plant and equipment, net of accumulated depreciation of $1,597,284 and $1,538,836		2,582,633			2,542,776
Regulatory assets		110,611			110,718
Other		443,294			456,134
Goodwill and other intangibles, net		88,598			89,580

	$	10,020,728		$	9,951,577

Liabilities and stockholders’ equity
Liabilities
Accounts payable	$	188,241		$	183,336
Deposit liabilities		4,546,855			4,557,419
Short-term borrowings		296,493			141,758
Other borrowings		1,671,655			1,622,294
Long-term debt, net		1,033,089			1,142,993
Deferred income taxes		183,420			207,997
Regulatory liabilities		229,928			219,204
Contributions in aid of construction		262,036			256,263
Other		369,577			369,390

		8,781,294			8,700,654

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


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: 81,275,371 shares and 80,983,326 shares		1,023,564			1,018,966
Retained earnings		244,645			235,394
Accumulated other comprehensive loss, net of tax benefits		(63,068	)		(37,730	)

		1,205,141			1,216,630

	$	10,020,728		$	9,951,577

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

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)


(in thousands, except per share amounts and ratio of earnings to fixed charges)	Three months ended June 30						Six months ended June 30
	2006			2005			2006			2005
Revenues
Electric utility	$	503,967		$	429,730		$	979,023		$	804,505
Bank		102,556			91,946			202,560			189,170
Other		(1,554	)		586			(1,652	)		1,215

		604,969			522,262			1,179,931			994,890

Expenses
Electric utility		464,121			387,083			893,597			730,252
Bank		76,397			69,744			149,386			138,015
Other		3,722			3,986			7,068			8,503

		544,240			460,813			1,050,051			876,770

Operating income (loss)
Electric utility		39,846			42,647			85,426			74,253
Bank		26,159			22,202			53,174			51,155
Other		(5,276	)		(3,400	)		(8,720	)		(7,288	)

		60,729			61,449			129,880			118,120

Interest expense—other than bank		(19,134	)		(19,130	)		(38,251	)		(37,965	)
Allowance for borrowed funds used during construction		719			475			1,421			902
Preferred stock dividends of subsidiaries		(473	)		(474	)		(946	)		(950	)
Allowance for equity funds used during construction		1,588			1,182			3,136			2,269

Income from continuing operations before income taxes		43,429			43,502			95,240			82,376
Income taxes		16,205			15,167			35,679			29,946

Income from continuing operations		27,224			28,335			59,561			52,430
Discontinued operations-loss on disposal, net of income taxes		—			(755	)		—			(755	)

Net income	$	27,224		$	27,580		$	59,561		$	51,675

Basic earnings (loss) per common share
Continuing operations	$	0.34		$	0.35		$	0.73		$	0.65
Discontinued operations		—			(0.01	)		—			(0.01	)

	$	0.34		$	0.34		$	0.73		$	0.64

Diluted earnings (loss) per common share
Continuing operations	$	0.33		$	0.35		$	0.73		$	0.65
Discontinued operations		—			(0.01	)		—			(0.01	)

	$	0.33		$	0.34		$	0.73		$	0.64

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

Weighted-average number of common shares outstanding		81,100			80,814			81,041			80,741
Dilutive effect of stock options and dividend equivalents		332			399			319			404

Adjusted weighted-average shares		81,432			81,213			81,360			81,145

Ratio of earnings to fixed charges (SEC method)
Excluding interest on ASB deposits								2.21			2.07

Including interest on ASB deposits								1.85			1.81

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

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Changes in Stockholders’ Equity (unaudited)


	Common stock			Retained earnings			Accumulated other comprehensive loss			Total
(in thousands, except per share amounts)	Shares	Amount		Retained earnings			Accumulated other comprehensive loss			Total
Balance, December 31, 2005	80,983	$	1,018,966	$	235,394		$	(37,730	)	$	1,216,630
Comprehensive income:
Net income	—		—		59,561			—			59,561
Net unrealized losses on securities arising during the period, net of tax benefits of $16,697	—		—		—			(25,290	)		(25,290	)
Minimum pension liability adjustment, net of tax benefits of $30	—		—		—			(48	)		(48	)

Comprehensive income (loss)	—		—		59,561			(25,338	)		34,223

Issuance of common stock, net	292		4,598		—			—			4,598
Common stock dividends ($0.62 per share)	—		—		(50,310	)		—			(50,310	)

Balance, June 30, 2006	81,275	$	1,023,564	$	244,645		$	(63,068	)	$	1,205,141

Balance, December 31, 2004	80,687	$	1,010,090	$	208,998		$	(8,143	)	$	1,210,945
Comprehensive income:
Net income	—		—		51,675			—			51,675
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	)
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $70	—		—		—			(106	)		(106	)

Comprehensive income (loss)	—		—		51,675			(3,616	)		48,059

Issuance of common stock, net	247		7,182		—			—			7,182
Common stock dividends ($0.62 per share)	—		—		(50,100	)		—			(50,100	)

Balance, June 30, 2005	80,934	$	1,017,272	$	210,573		$	(11,759	)	$	1,216,086

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

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)


Six months ended June 30	2006			2005
(in thousands)
Cash flows from operating activities
Net income	$	59,561		$	51,675
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment		70,574			66,974
Other amortization		4,211			5,861
Reversal of allowance for loan losses		—			(3,100	)
Deferred income taxes		(7,498	)		2,066
Allowance for equity funds used during construction		(3,136	)		(2,269	)
Excess tax benefits from share-based payment arrangements		(567	)		—
Changes in assets and liabilities, net of effects from the disposal of businesses
Decrease (increase) in accounts receivable and unbilled revenues, net		1,656			(3,895	)
Decrease (increase) in federal tax deposit		30,000			(30,000	)
Increase (decrease) in accounts payable		4,905			(7,921	)
Changes in other assets and liabilities		(12,017	)		(9,224	)

Net cash provided by operating activities		147,689			70,167

Cash flows from investing activities
Available-for-sale investment and mortgage-related securities purchased		(175,000	)		(174,436	)
Principal repayments on available-for-sale mortgage-related securities		254,109			353,425
Proceeds from sale of available-for-sale mortgage-related securities		—			28,039
Net increase in loans held for investment		(159,096	)		(179,326	)
Capital expenditures		(97,691	)		(86,146	)
Contributions in aid of construction		10,622			5,444
Other		1,436			1,144

Net cash used in investing activities		(165,620	)		(51,856	)

Cash flows from financing activities
Net increase (decrease) in deposit liabilities		(10,564	)		157,150
Net increase in short-term borrowings with maturities of three months or less		109,845			50,277
Proceeds from short-term borrowings with maturities of greater than three months		44,890			—
Net increase in retail repurchase agreements		21,650			8,713
Proceeds from other borrowings		635,840			683,205
Repayments of other borrowings		(608,595	)		(806,331	)
Proceeds from issuance of long-term debt		—			53,643
Repayment of long-term debt		(110,000	)		(53,000	)
Excess tax benefits from share-based payment arrangements		567			—
Net proceeds from issuance of common stock		2,481			2,918
Common stock dividends		(50,282	)		(50,073	)
Other		(7,628	)		(10,212	)

Net cash provided by financing activities		28,204			36,290

Cash flows from discontinued operations-net cash provided by (used in) operating activities (revised see Note 8)		6,846			(1,836	)

Net increase in cash and equivalents and federal funds sold		17,119			52,765
Cash and equivalents and federal funds sold, beginning of period		208,947			173,629

Cash and equivalents and federal funds sold, end of period	$	226,066		$	226,394

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

Hawaiian Electric Industries, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) Basis of presentation

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, 2005 and the unaudited consolidated financial statements and the notes thereto in HEI’s Quarterly Report on SEC Form 10-Q for the quarter ended March 31, 2006.

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 30, 2006 and December 31, 2005 and the results of its operations for the three and six months ended June 30, 2006 and 2005 and its cash flows for the six months ended June 30, 2006 and 2005. 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.

(2) Segment financial information


(in thousands)	Electric Utility		Bank		Other			Total
Three months ended June 30, 2006
Revenues from external customers	$	503,897	$	102,556	$	(1,484	)	$	604,969
Intersegment revenues (eliminations)		70		—		(70	)		—

Revenues		503,967		102,556		(1,554	)		604,969

Profit (loss)*		28,109		26,159		(10,839	)		43,429
Income taxes (benefit)		10,823		9,941		(4,559	)		16,205

Income (loss) from continuing operations		17,286		16,218		(6,280	)		27,224

Six months ended June 30, 2006
Revenues from external customers		978,883		202,560		(1,512	)		1,179,931
Intersegment revenues (eliminations)		140		—		(140	)		—

Revenues		979,023		202,560		(1,652	)		1,179,931

Profit (loss)*		62,206		53,174		(20,140	)		95,240
Income taxes (benefit)		23,932		20,129		(8,382	)		35,679

Income (loss) from continuing operations		38,274		33,045		(11,758	)		59,561

Assets (at June 30, 2006, including net assets of discontinued operations)	$	3,139,155		6,866,794		14,779		$	10,020,728

Three months ended June 30, 2005
Revenues from external customers	$	429,683	$	91,946	$	633		$	522,262
Intersegment revenues (eliminations)		47		—		(47	)		—

Revenues		429,730		91,946		586			522,262

Profit (loss)*		31,890		22,183		(10,571	)		43,502
Income taxes (benefit)		12,246		8,631		(5,710	)		15,167

Income (loss) from continuing operations		19,644		13,552		(4,861	)		28,335

Six months ended June 30, 2005
Revenues from external customers		804,458		189,170		1,262			994,890
Intersegment revenues (eliminations)		47		—		(47	)		—

Revenues		804,505		189,170		1,215			994,890

Profit (loss)*		51,973		51,106		(20,703	)		82,376
Income taxes (benefit)		19,944		19,793		(9,791	)		29,946

Income (loss) from continuing operations		32,029		31,313		(10,912	)		52,430

Assets (at June 30, 2005, including net assets of discontinued operations)		2,923,097		6,816,549		67,425			9,807,071

*	Income (loss) before income taxes.

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.

(3) Electric utility subsidiary

For HECO’s consolidated financial information, including its commitments and contingencies, see pages 15 through 35.

(4) Bank subsidiary

Selected financial information

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

Consolidated Balance Sheet Data (unaudited)


(in thousands)	June 30, 2006			December 31, 2005
Assets
Cash and equivalents	$	139,539		$	150,130
Federal funds sold		81,121			57,434
Available-for-sale investment and mortgage-related securities		2,506,444			2,629,351
Investment in stock of Federal Home Loan Bank of Seattle, at cost		97,764			97,764
Loans receivable, net		3,717,501			3,566,834
Other		235,950			244,443
Goodwill and other intangibles, net		88,475			89,379

	$	6,866,794		$	6,835,335

Liabilities and stockholder’s equity
Deposit liabilities–noninterest-bearing	$	624,246		$	624,497
Deposit liabilities–interest-bearing		3,922,609			3,932,922
Other borrowings		1,671,655			1,622,294
Other		100,944			98,189

		6,319,454			6,277,902

Common stock		322,318			321,538
Retained earnings		286,997			272,545
Accumulated other comprehensive loss, net of tax benefits		(61,975	)		(36,650	)

		547,340			557,433

	$	6,866,794		$	6,835,335

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

Consolidated Statements of Income Data (unaudited)


	Three months ended June 30				Six months ended June 30
(in thousands)	2006		2005		2006		2005
Interest and dividend income
Interest and fees on loans	$	57,323	$	50,657	$	112,476	$	99,170
Interest and dividends on investment and mortgage-related securities		30,870		27,523		60,947		62,386

		88,193		78,180		173,423		161,556

Interest expense
Interest on deposit liabilities		17,001		12,460		32,394		24,477
Interest on other borrowings		18,308		16,893		35,470		34,641

		35,309		29,353		67,864		59,118

Net interest income		52,884		48,827		105,559		102,438
Reversal of allowance for loan losses		—		—		—		(3,100	)

Net interest income after reversal of allowance for loan losses		52,884		48,827		105,559		105,538

Noninterest income
Fees from other financial services		6,742		6,333		13,182		12,196
Fee income on deposit liabilities		4,376		4,092		8,565		8,263
Fee income on other financial products		2,132		2,154		4,569		4,589
Gain on sale of securities		—		175		—		175
Other income		1,113		1,012		2,821		2,391

		14,363		13,766		29,137		27,614

Noninterest expense
Compensation and employee benefits		17,476		17,441		35,313		34,068
Occupancy		4,490		4,088		8,953		8,106
Equipment		3,636		3,302		7,132		6,701
Services		4,124		3,941		7,841		7,608
Data processing		2,547		2,503		5,007		5,548
Other expenses		8,815		9,116		17,276		19,966

		41,088		40,391		81,522		81,997

Income before minority interests and income taxes		26,159		22,202		53,174		51,155
Minority interests		—		18		—		45
Income taxes		9,941		8,631		20,129		19,793

Income before preferred stock dividends		16,218		13,553		33,045		31,317
Preferred stock dividends		—		1		—		4

Net income for common stock	$	16,218	$	13,552	$	33,045	$	31,313

Other borrowings consisted of securities sold under agreements to repurchase and advances from the Federal Home Loan Bank (FHLB) of Seattle of $834 million and $838 million, respectively, as of June 30, 2006 and $687 million and $935 million, respectively, as of December 31, 2005.

As of June 30, 2006, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.2 billion. As of June 30, 2006, ASB had commitments to sell nonresidential loans of $12.9 million.

In the first quarter of 2005, ASB recorded a $2 million reserve, net of taxes, for interest on the potential taxes related to the disputed timing of dividend income recognition because of a change in ASB’s 2000 and 2001 tax year-ends (see Note 10).

(5) Retirement benefits

For the first six months of 2006, ASB paid $2 million and HECO paid $5 million of contributions to the retirement benefit plans, compared to $6 million and $5 million, respectively, in the first six months of 2005. The Company’s current estimate of contributions to the retirement benefit plans in 2006 is $14 million, compared to contributions of $25 million in 2005.

The components of net periodic benefit cost were as follows:


	Three months ended June 30												Six months ended June 30
	Pension benefits						Other benefits						Pension benefits						Other benefits
(in thousands)	2006			2005			2006			2005			2006			2005			2006			2005
Service cost	$	8,236		$	7,390		$	1,278		$	1,345		$	16,327		$	14,673		$	2,549		$	2,618
Interest cost		13,645			13,031			2,578			2,744			27,121			26,089			5,310			5,552
Expected return on plan assets		(18,089	)		(18,535	)		(2,493	)		(2,440	)		(35,842	)		(36,909	)		(4,959	)		(4,925	)
Amortization of unrecognized transition obligation		1			1			785			785			2			2			1,569			1,569
Amortization of prior service cost (gain)		14			(165	)		4			(3	)		(142	)		(311	)		7			—
Recognized actuarial loss (gain)		2,917			1,402			(18	)		72			6,028			2,996			206			231

Net periodic benefit cost	$	6,724		$	3,124		$	2,134		$	2,503		$	13,494		$	6,540		$	4,682		$	5,045

Of the net periodic benefit costs, the Company recorded expense of $14 million and $9 million in the first six months of 2006 and 2005, respectively, and charged the remaining amounts primarily to electric utility plant.

(6) Share-based compensation

Under the 1987 Stock Option and Incentive Plan, as amended (SOIP), HEI may issue an aggregate of 9.3 million shares of common stock (5,158,493 shares unissued as of June 30, 2006) to officers and key employees as incentive stock options, nonqualified stock options (NQSOs), restricted stock, stock appreciation rights (SARs), stock payments or dividend equivalents. HEI has issued NQSOs, restricted stock, SARs, and dividend equivalents. All information presented has been adjusted for the 2-for-1 stock split in June 2004.

For the NQSOs and SARs, the exercise price of each NQSO or SAR generally equals the fair market value of HEI’s stock on or near the date of grant. NQSOs, SARs and related dividend equivalents issued in the form of stock awarded through 2004 generally become exercisable in installments of 25% each year for four years, and expire if not exercised ten years from the date of the grant. The 2005 SARs awards, which have a ten year exercise life, generally become exercisable at the end of four years with the related dividend equivalents issued in the form of stock on an annual basis. Accelerated vesting is provided in the event of a change-in-control or upon retirement.

Restricted stock grants generally become unrestricted three to five years after the date of grant and restricted stock compensation expense has been recognized in accordance with the fair value based method of accounting.

The Company recorded share-based compensation expense in the first six months of 2006 and 2005 of $0.9 million and $2.8 million, respectively. In the second quarter of 2006 and 2005, the Company recorded share-based compensation expense of $0.3 million and $1.6 million, respectively. The Company recorded related income tax benefit (including a valuation allowance due to limits on the deductibility of executive compensation) on share-based compensation expense in the first six months of 2006 and 2005 of $0.5 million and $0.9 million, respectively. In the second quarter of 2006 and 2005, the Company recorded related income tax benefit of $0.3 million, and $0.6 million, respectively. No share-based compensation cost has been capitalized.

Also, as a result of the changes enacted in Section 409A of the Internal Revenue Code of 1986, as amended (Section 409A) in December 2005, a total of 61,482 dividend equivalent shares were distributed to SOIP participants in February 2006 for the NQSO grants made from 2001 to 2003 and the SARs grants made from 2004 to 2005. The gross amount of 69,737 dividend equivalent shares subject to Section 409A was reduced by 8,255 shares because the exercise prices of the SARs grants exceeded the value of the underlying common stock as of December 31, 2005. The intrinsic value of the Section 409A dividend equivalent distribution was $1.6 million. The Company recorded related income tax benefits of $0.6 million. During the second quarter of 2006, 10,236 dividend equivalent shares subject to Section 409A, with an intrinsic value of $0.3 million and related tax benefit of $0.1 million, were distributed to SOIP participants who retired. At the election of SOIP participants, retirees may take distributions of dividend equivalents subject to Section 409A at the time of retirement rather than at the end of the calendar year.

In place of a SARs grant for 2006, as described under “Restricted stock,” the Company instead awarded restricted stock. For all share-based compensation, the estimated forfeiture rate is 1.4%.

Nonqualified stock options

Information about HEI’s NQSOs is summarized as follows:


June 30, 2006		Outstanding				Exercisable
Year of grant	Range of exercise prices	Number of options	Weighted- average remaining contractual life	Weighted- average exercise price		Number of options	Weighted- average remaining contractual life	Weighted- average exercise price
1998	$20.50	6,000	1.8	$	20.50	6,000	1.8	$	20.50
1999	17.61 -17.63	65,000	3.0		17.62	65,000	3.0		17.62
2000	14.74	52,000	3.8		14.74	52,000	3.8		14.74
2001	17.96	138,500	4.7		17.96	138,500	4.7		17.96
2002	21.68	150,000	5.7		21.68	150,000	5.7		21.68
2003	20.49	401,000	5.8		20.49	321,000	5.5		20.49

	$14.74 – 21.68	812,500	5.2	$	19.68	732,500	5.0	$	19.59

As of December 31, 2005, NQSOs outstanding totaled 929,000, with a weighted-average exercise price of $19.88. In the second quarter of 2006 and 2005, no NQSOs were granted, forfeited or expired; 197,500 shares and 277,000 shares vested with an aggregate fair value of $0.9 million and $1.2 million, respectively. In the first quarter of 2006 and 2005, no NQSOs were granted, vested, forfeited or expired.

During the first six months of 2006, 116,500 shares were exercised, with a weighted-average exercise price of $21.30. Cash received from these exercises was $2.5 million and the intrinsic value (amount by which the fair market value of the underlying stock and the related dividend equivalents exceeds the exercise price of the option) of the shares was $1.2 million. The tax benefit realized for the tax deduction from these exercises was $0.5 million. During the second quarter of 2006, 110,500 shares were exercised, with a weighted-average exercise price of $21.52. Cash received from these exercises was $2.4 million and the intrinsic value of the shares was $1.1 million. The tax benefit realized for the tax deduction from these exercises was $0.4 million.

During the second quarter of 2005, 153,500 shares were exercised, with a weighted-average exercise price of $19.01. Cash received from these exercises was $2.9 million and the intrinsic value of the shares was $1.8 million. The tax benefit realized for the tax deduction from these exercises was $0.4 million. There were no exercises in the first quarter of 2005.

As of June 30, 2006, NQSO shares outstanding and exercisable had an aggregate intrinsic value (including dividend equivalents) of $10.5 million and $9.7 million, respectively.

As of June 30, 2006, there was $0.2 million of total unrecognized compensation cost related to nonvested NQSOs and that cost is expected to be recognized over a weighted average period of 10 months.

Stock appreciation rights

Information about HEI’s SARs is summarized as follows:


June 30, 2006		Outstanding				Exercisable
Year of grant	Range of exercise prices	Number of shares underlying SARs	Weighted- average remaining contractual life	Weighted- average exercise price		Number of shares underlying SARs	Weighted- average remaining contractual life	Weighted- average exercise price
2004	$26.02	325,000	5.6	$	26.02	235,000	4.8	$	26.02
2005	26.18	554,000	7.1		26.18	160,000	2.9		26.18

	$26.02 – 26.18	879,000	6.5	$	26.12	395,000	4.0	$	26.08

As of December 31, 2005, the shares underlying SARs outstanding totaled 879,000, with a weighted-average exercise price of $26.12. As of June 30, 2006, the SARs outstanding and exercisable had an aggregate intrinsic value (including dividend equivalents) of $2.5 million and $1.0 million, respectively. During the first six months of 2006, no SARs were granted, exercised, forfeited or expired; 313,750 shares vested with a fair value of $1.7 million. In the first quarter of 2006, no SARs were granted, vested, forfeited or expired. During the first six months of 2005 554,000 SARs shares were granted, 24,000 shares were exercised, no shares were forfeited or expired; 105,250 shares vested with a fair value of $0.5 million. In the first quarter of 2005, no SARs were granted, vested, forfeited or expired.

During the second quarter of 2005, 24,000 SARs were exercised, with an exercise price of $26.02. The intrinsic value of this exercise (amount by which the fair market value of the underlying stock and the related dividend equivalents exceeds the exercise price of the option) of the shares was $9,500. The tax benefit realized for the tax deduction from this exercise was $4,000.

As of June 30, 2006, there was $1.4 million of total unrecognized compensation cost related to SARs and that cost is expected to be recognized over a weighted average period of 2.6 years.

The weighted-average fair value of each of the SARs granted during 2005 was $5.82 (at grant date). For 2005, the weighted-average assumptions used to estimate fair value include: risk-free interest rate of 4.1%, expected volatility of 18.1%, expected dividend yield of 5.9%, term of 10 years and expected life of 4.5 years. The weighted-average fair value of the SARs grant is estimated on the date of grant using a Binomial Option Pricing Model. See below for discussion of 2005 grant modification. The expected volatility is based on historical price fluctuations. The Company believes that historical volatility is appropriate based upon the Company’s business model and strategies.

Section 409A modification

As noted above, in December 2005, to comply with Section 409A, HEI modified certain provisions pertaining to the dividend equivalent rights attributable to the outstanding grants of NQSOs and SARs held by 40 employees under the 1987 HEI Stock Option and Incentive Plan, as amended. The modifications apply to the NQSOs granted in 2001, 2002, and 2003 and the SARs granted in 2004 and 2005 and in general accelerate the distribution of dividend equivalent shares earned after 2004. When a share-based award is modified, the Company recognizes the incremental compensation cost, which is measured as the excess, if any, of the fair value of the modified award over the fair value of the original award immediately before its terms are modified.

The assumptions used to estimate fair value at the time of the Section 409A modification for the 2005 SARs include: risk-free interest rate of 4.4%, expected volatility of 14.9%, original term of 10 years and expected dividend yield of 4.6%. The expected life used at the time of modification was 4.2 years for 2005. As of December 7, 2005, the fair value of modified 2005 SARs, the fair value of original 2005 SARs and the additional compensation cost to be recognized per grant was $5.07, $4.95 and $0.12, respectively. The additional compensation cost for the Section 409A modification was not material.

Restricted stock

As of December 31, 2005, restricted stock shares outstanding totaled 41,000, with a weighted-average grant date fair value of $23.50. As of June 30, 2006, restricted stock shares outstanding totaled 101,800, with a weighted-average grant date fair value of $25.18. The fair value of a grant of a restricted stock share is the closing price of HEI common stock on the date of grant.

During the first six months of 2006, no restricted stock shares vested or were forfeited; 60,800 shares with a fair market value of $1.6 million were granted. In the first quarter of 2006, no restricted stock shares were granted, vested, or forfeited. During the first six months of 2005, no restricted stock shares vested or were forfeited; 9,000 shares with a fair market value of $0.2 million were granted. In the first quarter of 2005, no restricted stock shares were granted, vested, or forfeited.

The tax benefit realized for the tax deductions from restricted stock dividends were immaterial for the first six months of 2006 and 2005.

As of June 30, 2006, there was $1.8 million of total unrecognized compensation cost related to nonvested restricted stock. The cost is expected to be recognized over a period of 3.7 years.

(7) Commitments and contingencies

See Note 4, “Bank subsidiary,” above and Note 5, “Commitments and contingencies,” of HECO’s “Notes to Consolidated Financial Statements.”

(8) Cash flows

Supplemental disclosures of cash flow information

For the six months ended June 30, 2006 and 2005, the Company paid interest amounting to $94.9 million and $88.4 million, respectively.

For the six months ended June 30, 2006 and 2005, the Company paid income taxes amounting to $3.9 million and $19.5 million (including payment of bank franchise taxes and federal income taxes related to a prior year settlement), respectively.

Supplemental disclosures of noncash activities

Noncash increases in common stock for director and officer compensatory plans were $1.5 million and $4.2 million for the six months ended June 30, 2006 and 2005, respectively.

Revised cash flows from discontinued operations

The Company has separately disclosed the operating, investing and financing portions of the cash flows attributable to its discontinued operations for the first six months of 2006, which in the first six months of 2005 were reported on a combined basis as a single amount. For the first six months of 2006 and 2005, there were no cash flows from investing and financing activities from the Company’s discontinued operations.

(9) Recent accounting pronouncements and interpretations

For a discussion of a recent accounting pronouncement regarding variable interest entities (VIEs), see Note 7 of HECO’s “Notes to Consolidated Financial Statements.”

Share-based payment

In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment,” which requires companies to recognize the grant-date fair value of stock options and other equity-based compensation issued to employees in the income statement. In March 2005, the SEC issued Staff Accounting Bulletin (SAB) No. 107, which provides accounting, disclosure, valuation and other guidance related to share-based payment arrangements. The Company adopted the provisions of SFAS No. 123 (revised 2004) using a modified prospective application and the guidance in SAB No. 107 on January 1, 2006 and the net income impact of adoption was immaterial. Since the Company adopted the recognition provisions of SFAS No. 123 as of January 1, 2002, the only expense recognition change the Company made upon adoption of SFAS No. 123 (revised 2004) was how it accounts for forfeitures. The average annual forfeiture rate for 1996 through 2005 was 1.4% and historically has not been significant. In accordance with SFAS No. 123 (revised 2004), expanded disclosures are included in Note 6.

Accounting for certain hybrid financial instruments

In March 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments.” This statement amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” This statement permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, and clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives. SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of the first fiscal year that begins after September 15, 2006. The Company will adopt SFAS No. 155 on January 1, 2007. Because the impact of adopting the provisions of SFAS No. 155 will be dependent on future events and circumstances, management cannot predict such impact.

Accounting for servicing of financial assets

In March 2006, the FASB issued SFAS No. 156, “Accounting for Servicing of Financial Assets.” This statement amends SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” This statement requires an entity to recognize in certain situations a servicing asset or servicing liability when it undertakes an obligation to service a financial asset, requires all separately recognized servicing assets and liabilities to be initially measured at fair value (if practicable), permits alternative subsequent measurement methods for each class of servicing assets and liabilities, permits a limited one-time reclassification of available-for-sale securities to trading securities at adoption, requires separate presentation of servicing assets and liabilities subsequently measured at fair value in the balance sheet and requires additional disclosures. SFAS No. 156 must be adopted by the beginning of the first fiscal year that begins after September 15, 2006. The Company will adopt SFAS No. 156 on January 1, 2007 and management does not expect the impact of the adoption of the provisions will be material to the Company’s financial statements.

Accounting for uncertainty in income taxes

In June 2006, the FASB issued FIN No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109.” This interpretation prescribes a “more-likely-than-not” recognition threshold and measurement attribute (the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement with tax authorities) for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN No. 48 is effective for fiscal years beginning after December 15, 2006. The Company will adopt FIN No. 48 on January 1, 2007 and has not yet determined the impact of these provisions on the Company’s results of operations, financial condition or liquidity.

Cash flows relating to income taxes generated by a leveraged lease transaction

In July 2006, the FASB issued FASB Staff Position (FSP) No. 13-2, “Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction,” which requires a recalculation of the rate of return and the allocation of income to positive investment years from the inception of the lease if there is a change or projected change in the timing of cash flows relating to income taxes generated by the leveraged lease. The amounts comprising the net leveraged lease investment would be adjusted to the recalculated amounts, and the change in the net investment would be recognized as a gain or loss in the year in which the projected cash flows and/or assumptions change. FSP No. 13-2 is effective for fiscal years beginning after December 15, 2006. The Company will adopt FSP No. 13-2 on January 1, 2007. Based on current circumstances, the adoption of the provisions of FSP No. 13-2 will have no effect on the Company’s financial statements.

(10) Income taxes

In the first quarter of 2005, the Company recorded a $2 million reserve, net of taxes, for interest on the potential taxes related to the disputed timing of dividend income recognition because of a change in ASB’s 2000 and 2001 tax year-ends. In the second quarter of 2005, the Company made a $30 million deposit primarily to stop the further accrual of interest on the potential taxes related to the disputed timing of dividend income recognition. Also in the second quarter of 2005, $1 million of income taxes and interest payable, net of taxes, were reversed due to the resolution of audit issues with the Internal Revenue Service (IRS). In the fourth quarter of 2005, additional IRS audit issues were resolved, resulting in the reversal of $1 million of interest, net of taxes.

As of June 30, 2006, $1 million, net of tax effects, was reserved for potential tax issues and related interest. Although not probable, adverse developments on potential tax issues could result in additional charges to net income in the future. Based on information currently available, the Company believes it has adequately provided for potential income tax issues with federal and state tax authorities and related interest, and that the ultimate resolution of tax issues for all open tax periods will not have a material adverse effect on its results of operations, financial condition or liquidity.

(11) Investment in Hoku Scientific, Inc.

As of June 30, 2006, HEI Properties, Inc. (HEIPI) held shares of Hoku Scientific, Inc. (Hoku), a Hawaii fuel cell technology startup company. Prior to August 5, 2005, the investment had been accounted for under the cost method. Hoku went public and shares of Hoku began trading on the Nasdaq Stock Market on August 5, 2005. HEIPI was subject to certain “lockup” provisions that expired in February 2006. Since August 5, 2005, Hoku shares have been considered marketable and HEIPI has classified the shares as trading securities, carried at fair value with changes in fair value recorded in earnings. In the three and six months ended June 30, 2006, HEIPI recognized a $1.2 million loss (unrealized, net of taxes) and a $1.6 million loss (unrealized and realized, net of taxes), respectively, on the Hoku shares. As of June 30, 2006, HEIPI had sold 11% of its Hoku shares and carried its remaining investment in Hoku shares at $2 million.

(12) Credit agreements

Also effective April 3, 2006, HEI entered into a $75 million bilateral revolving unsecured credit agreement with Merrill Lynch Bank USA, which expires on December 27, 2006. Any draws on the facility bear interest, at the option of HEI, at the “Adjusted LIBO Rate” plus 57.5 basis points or the greater of (a) the “Prime Rate” and (b) the sum of the “Federal Funds Rate” plus 50 basis points, as defined in the agreement. The agreement’s conditions precedent to drawing on the line and events of default are similar to HEI’s $100 million revolving unsecured credit agreement.

These two facilities, currently totaling $175 million, are maintained to support the issuance of commercial paper, but also may be drawn for general corporate purposes. The facilities contain provisions for revised pricing in the event of a ratings change and replaced HEI’s four bilateral bank lines of credit totaling $80 million, which were terminated concurrently with the effectiveness of the new facilities. The Company used the new facilities to support the issuance of commercial paper to refinance $100 million of its Series C medium-term notes, which matured on April 10, 2006. As of July 31, 2006, the $175 million of credit facilities were undrawn.

See Note 10 of HECO’s “Notes to Consolidated Financial Statements” for a discussion of HECO’s credit facility.

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)


(in thousands, except par value)	June 30, 2006			December 31, 2005
Assets
Utility plant, at cost
Land	$	35,034		$	33,034
Plant and equipment		3,846,892			3,749,386
Less accumulated depreciation		(1,509,529	)		(1,456,537	)
Plant acquisition adjustment, net		119			145
Construction in progress		140,384			147,756

Net utility plant		2,512,900			2,473,784

Current assets
Cash and equivalents		3,374			143
Customer accounts receivable, net		126,198			123,895
Accrued unbilled revenues, net		88,355			91,321
Other accounts receivable, net		6,054			14,761
Fuel oil stock, at average cost		113,474			85,450
Materials and supplies, at average cost		30,124			26,974
Prepaid pension benefit cost		96,330			106,318
Other		9,214			8,584

Total current assets		473,123			457,446

Other long-term assets
Regulatory assets		110,611			110,718
Unamortized debt expense		14,005			14,361
Other		28,516			25,152

Total other long-term assets		153,132			150,231

	$	3,139,155		$	3,081,461

Capitalization and liabilities
Capitalization
Common stock, $6 2/3 par value, authorized 50,000 shares; outstanding 12,806 shares	$	85,387		$	85,387
Premium on capital stock		299,186			299,186
Retained earnings		663,579			654,686

Common stock equity		1,048,152			1,039,259
Cumulative preferred stock – not subject to mandatory redemption		34,293			34,293
Long-term debt, net		766,089			765,993

Total capitalization		1,848,534			1,839,545

Current liabilities
Short-term borrowings–nonaffiliates		163,476			136,165
Accounts payable		121,995			122,201
Interest and preferred dividends payable		11,484			9,990
Taxes accrued		143,306			133,583
Other		34,154			37,132

Total current liabilities		474,415			439,071

Deferred credits and other liabilities
Deferred income taxes		201,462			208,374
Regulatory liabilities		229,928			219,204
Unamortized tax credits		57,157			55,327
Other		65,623			63,677

Total deferred credits and other liabilities		554,170			546,582

Contributions in aid of construction		262,036			256,263

	$	3,139,155		$	3,081,461

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)


	Three months ended June 30						Six months ended June 30
(in thousands, except for ratio of earnings to fixed charges)	2006			2005			2006			2005
Operating revenues	$	503,350		$	428,807		$	977,321		$	802,497

Operating expenses
Fuel oil		192,314			148,775			367,652			264,401
Purchased power		122,438			106,369			240,158			207,585
Other operation		47,934			41,794			89,953			83,110
Maintenance		22,382			19,837			39,434			37,775
Depreciation		32,542			30,822			65,075			61,642
Taxes, other than income taxes		46,218			39,293			90,741			75,264
Income taxes		11,020			12,293			24,244			20,031

		474,848			399,183			917,257			749,808

Operating income		28,502			29,624			60,064			52,689

Other income
Allowance for equity funds used during construction		1,588			1,182			3,136			2,269
Other, net		521			777			1,430			1,620

		2,109			1,959			4,566			3,889

Income before interest and other charges		30,611			31,583			64,630			56,578

Interest and other charges
Interest on long-term debt		10,776			10,656			21,554			21,565
Amortization of net bond premium and expense		543			557			1,086			1,113
Other interest charges		2,226			702			4,139			1,775
Allowance for borrowed funds used during construction		(719	)		(475	)		(1,421	)		(902	)
Preferred stock dividends of subsidiaries		229			229			458			458

		13,055			11,669			25,816			24,009

Income before preferred stock dividends of HECO		17,556			19,914			38,814			32,569
Preferred stock dividends of HECO		270			270			540			540

Net income for common stock	$	17,286		$	19,644		$	38,274		$	32,029

Ratio of earnings to fixed charges (SEC method)								3.16			3.00

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Retained Earnings (unaudited)


	Three months ended June 30						Six months ended June 30
(in thousands)	2006			2005			2006			2005
Retained earnings, beginning of period	$	662,034		$	635,231		$	654,686		$	632,779
Net income for common stock		17,286			19,644			38,274			32,029
Common stock dividends		(15,741	)		(9,289	)		(29,381	)		(19,222	)

Retained earnings, end of period	$	663,579		$	645,586		$	663,579		$	645,586

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 Consolidated Financial Statements” for HECO.

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)


Six months ended June 30	2006			2005
(in thousands)
Cash flows from operating activities
Income before preferred stock dividends of HECO	$	38,814		$	32,569
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities
Depreciation of property, plant and equipment		65,075			61,642
Other amortization		3,801			4,568
Deferred income taxes		(6,912	)		1,336
Tax credits, net		2,459			1,385
Allowance for equity funds used during construction		(3,136	)		(2,269	)
Changes in assets and liabilities
Decrease in accounts receivable		6,404			599
Decrease (increase) in accrued unbilled revenues		2,966			(1,322	)
Increase in fuel oil stock		(28,024	)		(6,200	)
Increase in materials and supplies		(3,150	)		(3,579	)
Decrease in prepaid pension benefit cost		9,988			3,728
Increase in regulatory assets		(1,587	)		(1,167	)
Decrease in accounts payable		(206	)		(19,551	)
Increase (decrease) in taxes accrued		9,723			(109	)
Changes in other assets and liabilities		(3,009	)		(8,516	)

Net cash provided by operating activities		93,206			63,114

Cash flows from investing activities
Capital expenditures		(91,394	)		(83,516	)
Contributions in aid of construction		10,622			5,444
Other		193			1,423

Net cash used in investing activities		(80,579	)		(76,649	)

Cash flows from financing activities
Common stock dividends		(29,381	)		(19,222	)
Preferred stock dividends		(540	)		(540	)
Proceeds from issuance of long-term debt		—			53,643
Repayment of long-term debt		—			(47,000	)
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		27,311			34,023
Other		(6,786	)		(4,925	)

Net cash provided by (used in) financing activities		(9,396	)		15,979

Net increase in cash and equivalents		3,231			2,444
Cash and equivalents, beginning of period		143			327

Cash and equivalents, end of period	$	3,374		$	2,771

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

Hawaiian Electric Company, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) Basis of presentation

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 incorporated by reference in HECO’s Form 10-K for the year ended December 31, 2005 and the unaudited consolidated financial statements and the notes thereto in HECO’s Quarterly Report on SEC Form 10-Q for the quarter ended March 31, 2006.

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 30, 2006 and December 31, 2005, the results of their operations for the three and six months ended June 30, 2006 and 2005 and their cash flows for the six months ended June 30, 2006 and 2005. 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.

(2) Unconsolidated variable interest entities

HECO Capital Trust III

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 Hawaii Electric Light Company, Inc. (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 sheets as of June 30, 2006 and December 31, 2005 each 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 statements for six months ended June 30, 2006 and 2005 each consisted of $1.7 million of interest income received from the 2004 Debentures; $1.6 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.

Purchase power agreements

As of June 30, 2006, HECO and its subsidiaries had six purchase power agreements (PPAs) for a total of 540 megawatts (MW) of firm capacity, and other PPAs with smaller IPPs and Schedule Q providers that supplied as-available energy. Approximately 91% of the 540 MW of firm capacity is under PPAs, entered into before December 31, 2003, with AES Hawaii, Inc. (AES Hawaii), Kalaeloa Partners, L.P. (Kalaeloa), Hamakua Energy Partners, L.P. (HEP) and HPower. Purchases from all IPPs for the six months ended June 30, 2006 totaled $240 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPower totaling $63 million, $87 million, $32 million and $22 million, respectively. The primary business activities of these IPPs are the generation and sale of power to HECO and its subsidiaries (and municipal waste disposal in the case of HPower). Current financial information about the size, including total assets and revenues, for many of these IPPs is not publicly available.

Under FIN 46R, an enterprise with an interest in a VIE or potential VIE created before December 31, 2003 (and not thereafter materially modified) is not required to apply FIN 46R to that entity if the enterprise is unable to obtain, after making an exhaustive effort, the necessary information. HECO has reviewed its 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 to explain and repeat its request for information. (HECO and its subsidiaries excluded their Schedule Q providers from the scope of FIN 46R because their variable interest in the provider would not be significant to the utilities and they did not participate significantly in the design of the provider.) Some of the IPPs provided sufficient information for HECO to determine that the IPP was not a VIE, or was either a “business” or “governmental organization” (HPower) as defined under FIN 46R, and thus excluded from the scope of FIN 46R. Other IPPs, including the three largest, declined to provide the information necessary for HECO to determine the applicability of FIN 46R, and HECO was unable to apply FIN 46R to these IPPs. As required under FIN 46R, HECO has continued its efforts to obtain from the IPPs the information necessary to make the determinations required under FIN 46R. In January 2005 and 2006, 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, except that Kalaeloa and Kaheawa Wind Power, LLC (KWP) have now provided their information (see below).

If the requested information is ultimately received from the other IPPs, a possible outcome of future analysis is the consolidation of an IPP in HECO’s consolidated financial statements. The consolidation of any significant IPP could have a material effect on HECO’s consolidated financial statements, including the recognition of a significant amount of assets and liabilities, and, if such a consolidated IPP were operating at a loss and had insufficient equity, the potential recognition of such losses.

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

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

certified by the Federal Energy Regulatory Commission as a Qualifying Facility under the Public Utility Regulatory Policies Act of 1978.

Pursuant to the provisions of FIN 46R, HECO is deemed to have a variable interest in Kalaeloa by reason of the provisions of 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 the PPA, the PPA does not expose HECO to losses as the fuel and fuel related energy payments under the PPA have been approved by the PUC for recovery from customers through base electric rates and through HECO’s energy cost adjustment clause to the extent the fuel and fuel related energy payments are not included in base energy rates.

Kaheawa Wind Power, LLC. In December 2004, MECO executed a new PPA with KWP, which recently completed the installation of a 30 MW windfarm on Maui and began selling power to MECO in June 2006. KWP has provided information for MECO to determine if MECO must consolidate KWP, pursuant to the provisions of FIN 46R. Management has concluded that MECO does not have to consolidate KWP as MECO does not have a variable interest in KWP because the PPA does not require MECO to absorb variability of KWP.

Apollo Energy Corporation. In October 2004, HELCO and Apollo Energy Corporation (Apollo) executed a restated and amended PPA which enables Apollo to repower its 7 MW facility, and install additional capacity, for a total allowed capacity of 20.5 MW. The PUC approved the restated and amended PPA on March 10, 2005 and it became effective in April 2005. Due to initial problems with securing wind turbines from its supplier, Apollo had earlier informed HELCO that the project may be delayed. However, Apollo informed HELCO in May 2006 that its wind turbine supply problems have been resolved and it can now meet the April 2007 target for commercial operation. The PPA requires Apollo to provide information necessary to (1) determine if HELCO must consolidate Apollo under FIN 46R, (2) consolidate Apollo, if necessary, under FIN 46R, and (3) comply with Section 404 of Sarbanes-Oxley Act of 2002 (SOX). Management is in the process of obtaining the information necessary to complete its determination of whether Apollo is a VIE and, if so, whether HELCO is the primary beneficiary. Based on information currently available, management believes the impact on consolidated HECO’s financial statements of the consolidation of Apollo, if necessary, would not be material. However, depending on the magnitude of the capital additions contemplated in the PPA, the impact of a required consolidation of Apollo could be material in the future. If required to consolidate the financial statements of Apollo in the future and such consolidation had a material effect, HECO would retrospectively apply FIN 46R in accordance with SFAS No. 154, “Accounting Changes and Error Corrections.”

(3) Revenue taxes

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 months ended June 30, 2006 and 2005, HECO and its subsidiaries included approximately $87 million and $71 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

(4) Retirement benefits

In each of the first six months of 2006 and 2005, HECO and its subsidiaries paid contributions of $5 million to the retirement benefit plans. HECO and its subsidiaries’ current estimate of contributions to the retirement benefit plans in 2006 is $10 million, compared to their contributions of $18 million in 2005.

The components of net periodic benefit cost were as follows:


	Three months ended June 30												Six months ended June 30
	Pension benefits						Other benefits						Pension benefits						Other benefits
(in thousands)	2006			2005			2006			2005			2006			2005			2006			2005
Service cost	$	6,819		$	6,030		$	1,247		$	1,307		$	13,359		$	11,904		$	2,482		$	2,544
Interest cost		12,135			11,722			2,510			2,684			24,174			23,438			5,169			5,420
Expected return on plan assets		(16,301	)		(16,812	)		(2,452	)		(2,402	)		(32,233	)		(33,462	)		(4,879	)		(4,850	)
Amortization of unrecognized transition obligation		—			—			783			783			1			1			1,565			1,565
Amortization of prior service gain		(192	)		(197	)		—			—			(385	)		(385	)		—			—
Recognized actuarial loss (gain)		2,635			1,145			(19	)		59			5,349			2,402			194			206

Net periodic benefit cost	$	5,096		$	1,888		$	2,069		$	2,431		$	10,265		$	3,898		$	4,531		$	4,885

Of the net periodic benefit costs, HECO and its subsidiaries recorded expense of $11 million and $6 million in the first six months of 2006 and 2005, respectively, and charged the remaining amounts primarily to electric utility plant.

(5) Commitments and contingencies

Interim increases

On September 27, 2005, the PUC issued an Interim Decision and Order (D&O) granting a general rate increase on Oahu of 4.36%, or $53.3 million (3.33%, or $41.1 million excluding the transfer of certain costs from a surcharge line item on electric bills into base electricity charges). The tariff changes implementing the interim rate increase were effective September 28, 2005.

As of June 30, 2006, HECO and its subsidiaries had recognized $57 million of revenues with respect to interim orders ($19 million related to interim orders regarding certain integrated resource planning costs and $38 million related to the interim order with respect to Oahu’s general rate increase request described above), which revenues are subject to refund, with interest, if and to the extent they exceed the amounts allowed in final orders.

Energy cost adjustment clauses

On June 19, 2006, the PUC issued an order in HECO’s pending rate case, indicating that the record in the pending case has not been developed for the purpose of addressing the factors in Act 162, signed into law by the Governor of Hawaii on June 2, 2006. Act 162 states that any automatic fuel rate adjustment clause requested by a public utility in an application filed with the PUC shall be designed, as determined in the PUC’s discretion, to: (1) fairly share the risk of fuel cost changes between the public utility and its customers; (2) provide the public utility with sufficient incentive to reasonably manage or lower its fuel costs and encourage greater use of renewable energy; (3) allow the public utility to mitigate the risk of sudden or frequent fuel cost changes that cannot otherwise reasonably be mitigated through other commercially available means, such as through fuel hedging contracts; (4) preserve, to the extent reasonably possible, the public utility’s financial integrity; and (5) minimize, to the extent reasonably possible, the public utility’s need to apply for frequent applications for general rate increases to account for the changes to its fuel costs. While the PUC already reviews the automatic fuel rate adjustment clause in rate cases, under Act 162, these specific factors must be addressed in the record. The PUC’s order requested the parties in the rate case proceeding to meet informally to determine a procedural schedule to address the issues relating to HECO’s energy cost adjustment clause (ECAC) that are raised by Act 162. The parties in the rate case proceeding are HECO, the Consumer Advocate, and the federal Department of Defense (DOD).

On June 30, 2006, HECO and the Consumer Advocate filed a stipulation requesting the PUC not to review the Act 162 ECAC issues in this rate case since HECO’s application was filed and the record of this proceeding was completed before Act 162 was signed into law, and the settlement agreement entered into by the parties in this rate case included a provision allowing the existing ECAC to be continued. The DOD has indicated it does not object to

the stipulation that HECO and the Consumer Advocate filed, and HECO will be working with the parties on an amended stipulation, which all parties would sign.

Management cannot predict whether the PUC will accept the disposition of the Act 162 issue proposed in the stipulation or, if not, the procedural steps or procedural schedule that will be adopted to address the issues that are raised by Act 162, the ultimate outcome of these issues, the effect of these issues on the operation of the ECAC as it relates to the electric utilities or the timing of the PUC’s issuance of a final D&O in HECO’s pending rate case.

HELCO power situation

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

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

Waimana filed four appeals to the Hawaii Supreme Court from judgments of the Third Circuit Court involving (i) vacating of a November 2002 Final Judgment which had halted construction; (ii) upholding the BLNR 2003 construction period extension; (iii) upholding the BLNR’s approval of a revocable permit allowing HELCO to use brackish well water as the primary source of water for operating the Keahole plant; and (iv) upholding the BLNR’s approval of the long-term lease allowing HELCO to use brackish well water.

Favorable decisions by the Hawaii Supreme Court have been received on the first three of these appeals. In the first appeal, on May 18, 2006, the Hawaii Supreme Court affirmed the Third Circuit Court’s decision vacating the November 2002 Final Judgment which had halted construction. (As a result of the Third Circuit’s decision, construction had recommenced in November 2003.) In the second and third appeals, on May 25, 2006 the Hawaii Supreme Court affirmed the Third Circuit Court’s decision on the construction period extension and dismissed the appeal of the Third Circuit’s judgment upholding the grant of the brackish water revocable permit as moot. The Supreme Court has not yet acted on the fourth appeal.

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 in HELCO’s favor, then the Settlement Agreement requires HELCO to undertake a number of actions 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). Many of these actions have already commenced.

HELCO’s plans for ST-7 are progressing. 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 of Hawaii Land Use Commission, which was approved in October 2005. In May 2006, HELCO obtained County rezoning to a “General Industrial” classification, and in June 2006, received approval for a covered source permit amendment to include selective catalytic reduction with the installation of ST-7. HELCO will commence construction of ST-7 as other necessary permits, including a building permit, are obtained.

Costs incurred; management’s evaluation. As of June 30, 2006, HELCO’s capitalized costs incurred in its efforts to put CT-4 and CT-5 into service and to support existing units (excluding costs for pre-air permit facilities) amounted to approximately $110 million, including $43 million for equipment and material purchases, $47 million for planning, engineering, permitting, site development and other costs and $20 million for allowance for funds used during construction (AFUDC) up to November 30, 1998, after which date HELCO has not accrued AFUDC. The $110 million of costs was reclassified from construction in progress to plant and equipment in 2004 and 2005 and depreciated beginning January 1 of the year following the reclassification.

Management believes that the prospects are good that the remaining Settlement Agreement conditions will be satisfied and that any further necessary permits will be obtained and that the remaining appeal 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 the PUC grants HELCO rate relief in the rate case commenced by HELCO in May 2006 in part to recover CT-4 and CT-5 costs. Management believes that no adjustment to costs incurred to put CT-4 and CT-5 into service is required as of June 30, 2006. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HELCO may be required to write off a material portion of these costs.

East Oahu Transmission Project (EOTP)

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

HECO continues to believe that the proposed reliability project (the East Oahu Transmission Project) is needed. In December 2003, HECO filed an application with the PUC requesting approval to commit funds (currently estimated at $60 million; see costs incurred below) for a revised EOTP using a 46 kV system. In March 2004, the PUC granted intervenor status to an environmental organization and three elected officials (collectively treated as one party) and a more limited participant status to four community organizations. The environmental review process has been completed and the PUC issued a Finding of No Significant Impact in April 2005. Subject to obtaining PUC approval and other construction permits, HECO plans to construct the revised project, none of which is in conservation district lands, in two phases. The first phase is currently projected to be completed in 2008, and the completion date of the second phase is being evaluated.

As of June 30, 2006, the accumulated costs recorded for the EOTP amounted to $28 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, $4 million of planning and permitting costs incurred after 2002, and $12 million for AFUDC. In written testimony filed in June 2005, the consultant for the Division of Consumer Advocacy, Department of Commerce and Consumer Affairs of the State of Hawaii (Consumer Advocate) contended that HECO should always have planned for a project using only the 46 kV system and recommended that HECO be required to expense the $12 million incurred before 2003, and the related AFUDC of $5 million. In rebuttal testimony filed in August 2005, HECO contested the consultant’s recommendation, emphasizing that the originally proposed 138 kV line would have been a more comprehensive and robust solution to the transmission concerns the project addressed. The PUC held an evidentiary hearing on HECO’s application in November 2005, and post-hearing briefing was completed in March 2006. Just prior to the evidentiary hearing, the PUC approved that part of a stipulation between HECO and the Consumer Advocate that this proceeding should determine whether HECO should be given approval to expend funds for the EOTP provided that no part of the EOTP costs may be recovered from ratepayers unless and until the PUC grants HECO recovery in a rate case (which is consistent with other projects), and that the issue as to whether the pre-2003 planning and permitting costs, and related AFUDC, should be included in the project costs is reserved to, and may be raised in, the next HECO rate case (or other proceeding) in which HECO seeks approval to recover the EOTP costs. Management believes no adjustment to project costs is required as of June 30, 2006. 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.

Environmental regulation

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

HECO, HELCO and MECO, like other utilities, periodically identify petroleum or other chemical releases into the environment associated with current operations and report and take action on these releases when and as required by applicable law and regulations. Except as otherwise disclosed herein, the Company believes the costs of responding to its 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 HEI and its subsidiaries to investigate whether releases from historical operations may have contributed to environmental impacts, and, where appropriate, respond to such releases, even if they were not inconsistent with law or standard industrial practices prevailing at the time when they occurred. Such releases may involve area-wide impacts contributed to by multiple potentially responsible parties.

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

In 2001, management developed a preliminary estimate of HECO’s share of costs for continuing investigative work, remedial activities and monitoring at the Iwilei Unit of approximately $1.1 million (which was expensed in 2001 and of which $0.6 million has been incurred through June 30, 2006). Because (1) the full scope and extent of additional investigative work, remedial activities and monitoring are unknown at this time, (2) the final cost allocation method among the PRPs has not yet been determined and (3) management cannot estimate the costs to be incurred (if any) for the sites other than the Iwilei Unit (including its Honolulu power plant site), the cost estimate may be subject to significant change and additional material investigative and remedial costs may be incurred.

HECO routinely maintains its facilities and has investigated its operations in the Iwilei area and ascertained that they are not releasing petroleum.

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

Clean Water Act. Section 316(b) of the federal Clean Water Act requires that the EPA ensure that existing power plant cooling water intake structures reflect the best technology available for minimizing adverse environmental

impacts. Effective September 9, 2004, the EPA issued a new rule, which establishes location and technology-based design, construction and capacity standards for existing cooling water intake structures. These standards will apply to HECO’s Kahe, Waiau and Honolulu generating stations unless the utility can demonstrate that at each facility implementation of these standards will result in costs either significantly higher than the EPA considered in establishing the standards for the facility or significantly greater than the benefits of meeting the standards. In either case, the EPA will then make a case-by-case determination of an appropriate performance standard. HECO has until March 2008 to make this showing or demonstrate compliance. HECO has retained a consultant to develop a cost effective compliance strategy and a preliminary assessment of technologies and operational measures. HECO is developing a monitoring program and plans to perform a cost-benefit analysis to demonstrate that HECO’s existing intake systems have minimal environmental impacts, which demonstration would exempt HECO from the standards. Concurrently, HECO will evaluate alternative compliance mechanisms allowed by the rule, some of which could entail significant capital expenditures to implement.

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. 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 on the grounds that the Circuit Court erred in its reliance on the doctrine of primary jurisdiction and the statute of limitations. In May 2006 the Hawaii Supreme Court affirmed the First Circuit Court’s rulings on all issues raised in the appeal, and in June 2006, the appellant’s motion for reconsideration was denied and the Hawaii Supreme Court filed its Notice and Judgment on Appeal. This closes the case on the merits for all defendants.

Collective bargaining agreements

Approximately 58% 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).

(6) Cash flows

Supplemental disclosures of cash flow information

For the six months ended June 30, 2006 and 2005, HECO and its subsidiaries paid interest amounting to $22.7 million and $23.1 million, respectively.

For the six months ended June 30, 2006 and 2005, HECO and its subsidiaries paid income taxes amounting to $5.5 million and $2.9 million, respectively.

Supplemental disclosure of noncash activities

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 $3.1 million and $2.3 million for the six months ended June 30, 2006 and 2005, respectively.

(7) Recent accounting pronouncements and interpretations

For a discussion of a recent accounting interpretation regarding uncertainty in income taxes, see Note 9 of HEI’s “Notes to Consolidated Financial Statements.”

Determining the variability to be considered in applying FIN 46R

In April 2006, the FASB issued FSP FIN 46R-6, “Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R).” This FSP provides guidance in applying FIN 46R, “Consolidation of Variable Interest Entities.” The variability that is considered can affect the determination of whether an entity is a VIE; which party, if any, is the primary beneficiary of the VIE; and calculations of expected losses and expected residual returns. A company is required to apply the guidance in the FSP prospectively to all entities (including newly created entities) with which that company first becomes involved and to all entities previously required to be analyzed under FIN 46R when a “reconsideration event” has occurred beginning the first day of the first reporting period beginning after June 15, 2006. HECO and its subsidiaries adopted FSP FIN 46R-6 on July 1, 2006 and the adoption had no effect on HECO and its subsidiaries’ financial statements.

(8) Income taxes

At June 30, 2006, $0.2 million, net of tax effects, was reserved for potential tax issues and related interest. Although not probable, adverse developments on potential issues could result in additional charges to net income in the future. Based on information currently available, HECO and its subsidiaries believe they have adequately provided for potential income tax issues with federal and state tax authorities and related interest, and that the ultimate resolution of tax issues for all open tax periods will not have a material adverse effect on 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
(in thousands)	2006			2005			2006			2005
Operating income from regulated and nonregulated activities before income taxes (per HEI consolidated statements of income)	$	39,846		$	42,647		$	85,426		$	74,253
Deduct:
Income taxes on regulated activities		(11,020	)		(12,293	)		(24,244	)		(20,031	)
Revenues from nonregulated activities		(617	)		(923	)		(1,702	)		(2,008	)
Add: Expenses from nonregulated activities		293			193			584			475

Operating income from regulated activities after income taxes (per HECO consolidated statements of income)	$	28,502		$	29,624		$	60,064		$	52,689

(10) Credit agreement

This facility is maintained to support the issuance of commercial paper, but also may be drawn for capital expenditures and general corporate purposes. This facility replaced HECO’s six bilateral bank lines of credit totaling $175 million, which were terminated concurrently with the effectiveness of the new syndicated facility. HECO plans to file with the PUC in the third quarter of 2006 an application seeking approval to extend the termination date of this credit agreement from March 29, 2007, to March 31, 2011. As of July 31, 2006, the $175 million of credit facilities were undrawn.

(11) Consolidating financial information

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 their obligations with respect to 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 Special Purpose Revenue Bonds issued for the benefit of HELCO and MECO and (b) relating to the trust preferred securities of Trust III. Also, see Note 2. HECO is also obligated, after the satisfaction of its obligations on its own preferred stock, 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.

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

June 30, 2006


(in thousands)	HECO			HELCO		MECO		RHI	Reclassifications and eliminations		HECO consolidated
Assets
Utility plant, at cost
Land	$	25,777		4,907		4,350		—	—		$	35,034
Plant and equipment		2,378,241		778,940		689,711		—	—			3,846,892
Less accumulated depreciation		(926,015	)	(288,116	)	(295,398	)	—	—			(1,509,529	)
Plant acquisition adjustment, net		—		—		119		—	—			119
Construction in progress		76,638		14,006		49,740		—	—			140,384

Net utility plant		1,554,641		509,737		448,522		—	—			2,512,900

Investment in subsidiaries, at equity		387,352		—		—		—	(387,352	)		—

Current assets
Cash and equivalents		2,977		330		6		61	—			3,374
Advances to affiliates		56,600		—		—		—	(56,600	)		—
Customer accounts receivable, net		84,162		21,898		20,138		—	—			126,198
Accrued unbilled revenues, net		60,084		14,313		13,958		—	—			88,355
Other accounts receivable, net		4,234		641		1,362		—	(183	)		6,054
Fuel oil stock, at average cost		87,963		8,994		16,517		—	—			113,474
Materials and supplies, at average cost		15,019		4,030		11,075		—	—			30,124
Prepaid pension benefit cost		75,405		14,157		6,768		—	—			96,330
Other		7,477		950		787		—	—			9,214

Total current assets		393,921		65,313		70,611		61	(56,783	)		473,123

Other long-term assets
Regulatory assets		81,481		14,153		14,977		—	—			110,611
Unamortized debt expense		9,545		2,309		2,151		—	—			14,005
Other		21,318		3,406		3,792		—	—			28,516

Total other long-term assets		112,344		19,868		20,920		—	—			153,132

	$	2,448,258		594,918		540,053		61	(444,135	)	$	3,139,155

Capitalization and liabilities
Capitalization
Common stock equity	$	1,048,152		190,452		196,884		16	(387,352	)	$	1,048,152
Cumulative preferred stock–not subject to mandatory redemption		22,293		7,000		5,000		—	—			34,293
Long-term debt, net		481,186		131,027		153,876		—	—			766,089

Total capitalization		1,551,631		328,479		355,760		16	(387,352	)		1,848,534

Current liabilities
Short-term borrowings–nonaffiliates		163,476		—		—		—	—			163,476
Short-term borrowings–affiliate		—		50,100		6,500		—	(56,600	)		—
Accounts payable		89,855		15,978		16,162		—	—			121,995
Interest and preferred dividends payable		7,555		1,863		2,312		—	(246	)		11,484
Taxes accrued		89,246		24,456		29,604		—	—			143,306
Other		19,210		3,293		11,543		45	63			34,154

Total current liabilities		369,342		95,690		66,121		45	(56,783	)		474,415

Deferred credits and other liabilities
Deferred income taxes		156,676		24,433		20,353		—	—			201,462
Regulatory liabilities		156,670		42,088		31,170		—	—			229,928
Unamortized tax credits		32,226		12,883		12,048		—	—			57,157
Other		21,864		34,614		9,145		—	—			65,623

Total deferred credits and other liabilities		367,436		114,018		72,716		—	—			554,170

Contributions in aid of construction		159,849		56,731		45,456		—	—			262,036

	$	2,448,258		594,918		540,053		61	(444,135	)	$	3,139,155

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

December 31, 2005


(in thousands)	HECO			HELCO		MECO		RHI	Reclassifications and eliminations		HECO consolidated
Assets
Utility plant, at cost
Land	$	25,699		3,018		4,317		—	—		$	33,034
Plant and equipment		2,304,142		766,714		678,530		—	—			3,749,386
Less accumulated depreciation		(898,351	)	(275,444	)	(282,742	)	—	—			(1,456,537	)
Plant acquisition adjustment, net		—		—		145		—	—			145
Construction in progress		108,060		11,414		28,282		—	—			147,756

Net utility plant		1,539,550		505,702		428,532		—	—			2,473,784

Investment in subsidiaries, at equity		383,715		—		—		—	(383,715	)		—

Current assets
Cash and equivalents		8		3		4		128	—			143
Advances to affiliates		49,700		—		5,250		—	(54,950	)		—
Customer accounts receivable, net		81,870		21,652		20,373		—	—			123,895
Accrued unbilled revenues, net		62,701		14,675		13,945		—	—			91,321
Other accounts receivable, net		10,212		2,772		1,185		—	592			14,761
Fuel oil stock, at average cost		64,309		7,868		13,273		—	—			85,450
Materials & supplies, at average cost		14,128		3,204		9,642		—	—			26,974
Prepaid pension benefit cost		82,497		15,388		8,433		—	—			106,318
Other		7,485		541		558		—	—			8,584

Total current assets		372,910		66,103		72,663		128	(54,358	)		457,446

Other long-term assets
Regulatory assets		81,682		14,596		14,440		—	—			110,718
Unamortized debt expense		9,778		2,362		2,221		—	—			14,361
Other		17,816		3,696		3,640		—	—			25,152

Total other long-term assets		109,276		20,654		20,301		—	—			150,231

	$	2,405,451		592,459		521,496		128	(438,073	)	$	3,081,461

Capitalization and liabilities
Capitalization
Common stock equity	$	1,039,259		189,407		194,190		118	(383,715	)	$	1,039,259
Cumulative preferred stock–not subject to mandatory redemption		22,293		7,000		5,000		—	—			34,293
Long-term debt, net		481,132		131,009		153,852		—	—			765,993

Total capitalization		1,542,684		327,416		353,042		118	(383,715	)		1,839,545

Current liabilities
Short-term borrowings-nonaffiliates		136,165		—		—		—	—			136,165
Short-term borrowings-affiliate		5,250		49,700		—		—	(54,950	)		—
Accounts payable		86,843		19,503		15,855		—	—			122,201
Interest and preferred dividends payable		7,217		1,311		1,664		—	(202	)		9,990
Taxes accrued		84,054		24,252		25,277		—	—			133,583
Other		24,971		3,566		7,791		10	794			37,132

Total current liabilities		344,500		98,332		50,587		10	(54,358	)		439,071

Deferred credits and other liabilities
Deferred income taxes		160,351		25,147		22,876		—	—			208,374
Regulatory liabilities		148,898		40,535		29,771		—	—			219,204
Unamortized tax credits		31,209		12,693		11,425		—	—			55,327
Other		21,522		31,781		10,374		—	—			63,677

Total deferred credits and other liabilities		361,980		110,156		74,446		—	—			546,582

Contributions in aid of construction		156,287		56,555		43,421		—	—			256,263

	$	2,405,451		592,459		521,496		128	(438,073	)	$	3,081,461

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Three months ended June 30, 2006


(in thousands)	HECO			HELCO		MECO		RHI		Reclassifications and eliminations		HECO consolidated
Operating revenues	$	339,213		80,736		83,401		—		—		$	503,350

Operating expenses
Fuel oil		130,757		18,035		43,522		—		—			192,314
Purchased power		86,527		30,118		5,793		—		—			122,438
Other operation		32,209		7,760		7,965		—		—			47,934
Maintenance		14,829		4,077		3,476		—		—			22,382
Depreciation		18,702		7,431		6,409		—		—			32,542
Taxes, other than income taxes		31,076		7,540		7,602		—		—			46,218
Income taxes		6,928		1,233		2,859		—		—			11,020

		321,028		76,194		77,626		—		—			474,848

Operating income		18,185		4,542		5,775		—		—			28,502

Other income
Allowance for equity funds used during construction		916		53		619		—		—			1,588
Equity in earnings of subsidiaries		6,376		—		—		—		(6,376	)		—
Other, net		918		58		284		(55	)	(684	)		521

		8,210		111		903		(55	)	(7,060	)		2,109

Income (loss) before interest and other charges		26,395		4,653		6,678		(55	)	(7,060	)		30,611

Interest and other charges
Interest on long-term debt		6,741		1,808		2,227		—		—			10,776
Amortization of net bond premium and expense		339		101		103		—		—			543
Other interest charges		2,168		650		92		—		(684	)		2,226
Allowance for borrowed funds used during construction		(409	)	(23	)	(287	)	—		—			(719	)
Preferred stock dividends of subsidiaries		—		—		—		—		229			229

		8,839		2,536		2,135		—		(455	)		13,055

Income (loss) before preferred stock dividends of HECO		17,556		2,117		4,543		(55	)	(6,605	)		17,556
Preferred stock dividends of HECO		270		133		96		—		(229	)		270

Net income (loss) for common stock	$	17,286		1,984		4,447		(55	)	(6,376	)	$	17,286

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Retained Earnings (unaudited)

Three months ended June 30, 2006


(in thousands)	HECO			HELCO		MECO		RHI		Reclassifications and eliminations		HECO consolidated
Retained earnings, beginning of period	$	662,034		89,275		101,093		(410	)	(189,958	)	$	662,034
Net income (loss) for common stock		17,286		1,984		4,447		(55	)	(6,376	)		17,286
Common stock dividends		(15,741	)	(1,451	)	(3,577	)	—		5,028			(15,741	)

Retained earnings, end of period	$	663,579		89,808		101,963		(465	)	(191,306	)	$	663,579

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Three months ended June 30, 2005


(in thousands)	HECO			HELCO		MECO		RHI		Reclassifications and eliminations		HECO consolidated

Operating revenues	$	287,073		68,484		73,250		—		—		$	428,807

Operating expenses
Fuel oil		98,955		13,678		36,142		—		—			148,775
Purchased power		79,375		23,313		3,681		—		—			106,369
Other operation		28,488		6,055		7,251		—		—			41,794
Maintenance		13,225		3,508		3,104		—		—			19,837
Depreciation		17,747		6,805		6,270		—		—			30,822
Taxes, other than income taxes		26,291		6,322		6,680		—		—			39,293
Income taxes		6,674		2,594		3,025		—		—			12,293

		270,755		62,275		66,153		—		—			399,183

Operating income		16,318		6,209		7,097		—		—			29,624

Other income
Allowance for equity funds used during construction		929		69		184		—		—			1,182
Equity in earnings of subsidiaries		8,997		—		—		—		(8,997	)		—
Other, net		977		89		135		(50	)	(374	)		777

		10,903		158		319		(50	)	(9,371	)		1,959

Income (loss) before interest and other charges		27,221		6,367		7,416		(50	)	(9,371	)		31,583

Interest and other charges
Interest on long-term debt		6,621		1,808		2,227		—		—			10,656
Amortization of net bond premium and expense		350		102		105		—		—			557
Other interest charges		705		249		122		—		(374	)		702
Allowance for borrowed funds used during construction		(369	)	(26	)	(80	)	—		—			(475	)
Preferred stock dividends of subsidiaries		—		—		—		—		229			229

		7,307		2,133		2,374		—		(145	)		11,669

Income (loss) before preferred stock dividends of HECO		19,914		4,234		5,042		(50	)	(9,226	)		19,914
Preferred stock dividends of HECO		270		133		96		—		(229	)		270

Net income (loss) for common stock	$	19,644		4,101		4,946		(50	)	(8,997	)	$	19,644

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Retained Earnings (unaudited)

Three months ended June 30, 2005


(in thousands)	HECO			HELCO		MECO		RHI		Reclassifications and eliminations		HECO consolidated
Retained earnings, beginning of period	$	635,231		86,565		95,756		(233	)	(182,088	)	$	635,231
Net income (loss) for common stock		19,644		4,101		4,946		(50	)	(8,997	)		19,644
Common stock dividends		(9,289	)	(1,785	)	(3,043	)	—		4,828			(9,289	)

Retained earnings, end of period	$	645,586		88,881		97,659		(283	)	(186,257	)	$	645,586

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Six months ended June 30, 2006


(in thousands)	HECO			HELCO		MECO		RHI		Reclassifications and eliminations		HECO consolidated

Operating revenues	$	657,558		160,187		159,576		—		—		$	977,321

Operating expenses
Fuel oil		246,492		38,137		83,023		—		—			367,652
Purchased power		171,981		58,164		10,013		—		—			240,158
Other operation		60,410		15,012		14,531		—		—			89,953
Maintenance		25,386		7,693		6,355		—		—			39,434
Depreciation		37,395		14,862		12,818		—		—			65,075
Taxes, other than income taxes		60,972		14,943		14,826		—		—			90,741
Income taxes		15,985		2,404		5,855		—		—			24,244

		618,621		151,215		147,421		—		—			917,257

Operating income		38,937		8,972		12,155		—		—			60,064

Other income
Allowance for equity funds used during construction		1,993		93		1,050		—		—			3,136
Equity in earnings of subsidiaries		13,033		—		—		—		(13,033	)		—
Other, net		2,159		128		511		(102	)	(1,266	)		1,430

		17,185		221		1,561		(102	)	(14,299	)		4,566

Income (loss) before interest and other charges		56,122		9,193		13,716		(102	)	(14,299	)		64,630

Interest and other charges
Interest on long-term debt		13,484		3,616		4,454		—		—			21,554
Amortization of net bond premium and expense		678		201		207		—		—			1,086
Other interest charges		4,038		1,232		135		—		(1,266	)		4,139
Allowance for borrowed funds used during construction		(892	)	(42	)	(487	)	—		—			(1,421	)
Preferred stock dividends of subsidiaries		—		—		—		—		458			458

		17,308		5,007		4,309		—		(808	)		25,816

Income (loss) before preferred stock dividends of HECO		38,814		4,186		9,407		(102	)	(13,491	)		38,814
Preferred stock dividends of HECO		540		267		191		—		(458	)		540

Net income (loss) for common stock	$	38,274		3,919		9,216		(102	)	(13,033	)	$	38,274

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Retained Earnings (unaudited)

Six months ended June 30, 2006


(in thousands)	HECO			HELCO		MECO		RHI		Reclassifications and eliminations		HECO consolidated
Retained earnings, beginning of period	$	654,686		88,763		99,269		(363	)	(187,669	)	$	654,686
Net income (loss) for common stock		38,274		3,919		9,216		(102	)	(13,033	)		38,274
Common stock dividends		(29,381	)	(2,874	)	(6,522	)	—		9,396			(29,381	)

Retained earnings, end of period	$	663,579		89,808		101,963		(465	)	(191,306	)	$	663,579

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Six months ended June 30, 2005


(in thousands)	HECO			HELCO		MECO		RHI		Reclassifications and eliminations		HECO consolidated
Operating revenues	$	533,201		132,349		136,947		—		—		$	802,497

Operating expenses
Fuel oil		169,839		28,985		65,577		—		—			264,401
Purchased power		157,601		43,095		6,889		—		—			207,585
Other operation		56,183		12,598		14,329		—		—			83,110
Maintenance		25,097		6,741		5,937		—		—			37,775
Depreciation		35,493		13,609		12,540		—		—			61,642
Taxes, other than income taxes		50,119		12,374		12,771		—		—			75,264
Income taxes		10,406		4,107		5,518		—		—			20,031

		504,738		121,509		123,561		—		—			749,808

Operating income		28,463		10,840		13,386		—		—			52,689

Other income
Allowance for equity funds used during construction		1,840		102		327		—		—			2,269
Equity in earnings of subsidiaries		15,390		—		—		—		(15,390	)		—
Other, net		2,010		148		201		(96	)	(643	)		1,620

		19,240		250		528		(96	)	(16,033	)		3,889

Income (loss) before interest and other charges		47,703		11,090		13,914		(96	)	(16,033	)		56,578

Interest and other charges
Interest on long-term debt		13,451		3,647		4,467		—		—			21,565
Amortization of net bond premium and expense		698		203		212		—		—			1,113
Other interest charges		1,708		529		181		—		(643	)		1,775
Allowance for borrowed funds used during construction		(723	)	(37	)	(142	)	—		—			(902	)
Preferred stock dividends of subsidiaries		—		—		—		—		458			458

		15,134		4,342		4,718		—		(185	)		24,009

Income (loss) before preferred stock dividends of HECO		32,569		6,748		9,196		(96	)	(15,848	)		32,569
Preferred stock dividends of HECO		540		267		191		—		(458	)		540

Net income (loss) for common stock	$	32,029		6,481		9,005		(96	)	(15,390	)	$	32,029

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Retained Earnings (unaudited)

Six months ended June 30, 2005


(in thousands)	HECO			HELCO		MECO		RHI		Reclassifications and eliminations		HECO consolidated
Retained earnings, beginning of period	$	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
Common stock dividends		(19,222	)	(3,461	)	(5,838	)	—		9,299			(19,222	)

Retained earnings, end of period	$	645,586		88,881		97,659		(283	)	(186,257	)	$	645,586

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Six months ended June 30, 2006


(in thousands)	HECO			HELCO		MECO		RHI		Reclassifications and eliminations		HECO consolidated
Cash flows from operating activities
Income (loss) before preferred stock dividends of HECO	$	38,814		4,186		9,407		(102	)	(13,491	)	$	38,814
Adjustments to reconcile income (loss) before preferred stock dividends of HECO to net cash provided by (used in) operating activities
Equity in earnings		(13,083	)	—		—		—		13,033			(50	)
Common stock dividends received from subsidiaries		9,446		—		—		—		(9,396	)		50
Depreciation of property, plant and equipment		37,395		14,862		12,818		—		—			65,075
Other amortization		2,152		214		1,435		—		—			3,801
Deferred income taxes		(3,675	)	(714	)	(2,523	)	—		—			(6,912	)
Tax credits, net		1,441		283		735		—		—			2,459
Allowance for equity funds used during construction		(1,993	)	(93	)	(1,050	)	—		—			(3,136	)
Changes in assets and liabilities
Decrease in accounts receivable		3,686		1,885		58		—		775			6,404
Decrease (increase) in accrued unbilled revenues		2,617		362		(13	)	—		—			2,966
Increase in fuel oil stock		(23,654	)	(1,126	)	(3,244	)	—		—			(28,024	)
Increase in materials and supplies		(891	)	(826	)	(1,433	)	—		—			(3,150	)
Decrease in prepaid pension benefit cost		7,092		1,231		1,665		—		—			9,988
Decrease (increase) in regulatory assets		(319	)	141		(1,409	)	—		—			(1,587	)
Increase (decrease) in accounts payable		3,012		(3,525	)	307		—		—			(206	)
Increase in taxes accrued		5,192		204		4,327		—		—			9,723
Changes in other assets and liabilities		(7,686	)	3,700		1,717		35		(775	)		(3,009	)

Net cash provided by (used in) operating activities		59,546		20,784		22,797		(67	)	(9,854	)		93,206

Cash flows from investing activities
Capital expenditures		(43,373	)	(18,151	)	(29,870	)	—		—			(91,394	)
Contributions in aid of construction		7,199		1,385		2,038		—		—			10,622
Advances from (to) affiliates		(6,900	)	—		5,250		—		1,650			—
Other		193		—		—		—		—			193

Net cash used in investing activities		(42,881	)	(16,766	)	(22,582	)	—		1,650			(80,579	)

Cash flows from financing activities
Common stock dividends		(29,381	)	(2,874	)	(6,522	)	—		9,396			(29,381	)
Preferred stock dividends		(540	)	(267	)	(191	)	—		458			(540	)
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		22,061		400		6,500		—		(1,650	)		27,311
Other		(5,836	)	(950	)	—		—		—			(6,786	)

Net cash used in financing activities		(13,696	)	(3,691	)	(213	)	—		8,204			(9,396	)

Net increase (decrease) in cash and equivalents		2,969		327		2		(67	)	—			3,231
Cash and equivalents, beginning of period		8		3		4		128		—			143

Cash and equivalents, end of period	$	2,977		330		6		61		—		$	3,374

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Six months ended June 30, 2005


(in thousands)	HECO			HELCO		MECO		RHI		Reclassifications and eliminations		HECO consolidated
Cash flows from operating activities
Income (loss) before preferred stock dividends of HECO	$	32,569		6,748		9,196		(96	)	(15,848	)	$	32,569
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	)
Common stock dividends received from subsidiaries		9,349		—		—		—		(9,299	)		50
Depreciation of property, plant and equipment		35,493		13,609		12,540		—		—			61,642
Other amortization		2,173		523		1,872		—		—			4,568
Deferred income taxes		(976	)	1,226		1,086		—		—			1,336
Tax credits, net		975		282		128		—		—			1,385
Allowance for equity funds used during construction		(1,840	)	(102	)	(327	)	—		—			(2,269	)
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	)
Decrease (increase) in fuel oil stock		(5,108	)	353		(1,445	)	—		—			(6,200	)
Increase in materials and supplies		(2,758	)	(353	)	(468	)	—		—			(3,579	)
Decrease in prepaid pension benefit cost		2,294		562		872		—		—			3,728
Decrease (increase) in regulatory assets		(457	)	372		(1,082	)	—		—			(1,167	)
Decrease in accounts payable		(15,612	)	(2,609	)	(1,330	)	—		—			(19,551	)
Increase (decrease) in taxes accrued		(2,212	)	570		1,533		—		—			(109	)
Changes in other assets and liabilities		(7,437	)	(912	)	752		16		(935	)		(8,516	)

Net cash provided by (used in) operating activities		31,164		20,277		21,510		(80	)	(9,757	)		63,114

Cash flows from investing activities
Capital expenditures		(47,481	)	(24,224	)	(11,811	)	—		—			(83,516	)
Contributions in aid of construction		3,036		1,636		772		—		—			5,444
Advances to affiliates		(6,650	)	—		(3,000	)	—		9,650			—
Other		1,423		—		—		—		—			1,423

Net cash used in investing activities		(49,672	)	(22,588	)	(14,039	)	—		9,650			(76,649	)

Cash flows from financing activities
Common stock dividends		(19,222	)	(3,461	)	(5,838	)	—		9,299			(19,222	)
Preferred stock dividends		(540	)	(267	)	(191	)	—		458			(540	)
Proceeds from issuance of long-term debt		46,643		5,000		2,000		—		—			53,643
Repayment of long-term debt		(40,000	)	(5,000	)	(2,000	)	—		—			(47,000	)
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		37,023		6,650		—		—		(9,650	)		34,023
Other		(4,872	)	(53	)	—		—		—			(4,925	)

Net cash provided by (used in) financing activities		19,032		2,869		(6,029	)	—		107			15,979

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

Cash and equivalents, end of period	$	533		561		1,459		218		—		$	2,771

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 and HECO’s 2005 Form 10-K and Form 10-Q for the three months ended March 31, 2006 and should be read in conjunction with the annual (as of and for the year ended December 31, 2005) and quarterly (as of and for the three months ended March 31, 2006, and as of and for the three and six months ended June 30, 2006) consolidated financial statements of HEI and HECO and accompanying notes.

HEI CONSOLIDATED

RESULTS OF OPERATIONS


	Three months ended June 30					% change		Primary reason(s) for significant change*
(in thousands, except per share amounts)	2006		2005			% change		Primary reason(s) for significant change*
Revenues	$	604,969	$	522,262		16		Increases for the electric utility and bank segments, slightly offset by a decrease for the “other” segment
Operating income		60,729		61,449		(1	)	Decreases for the electric utility and the “other” segments, partly offset by an increase for the bank segment
Income (loss) from:
Continuing operations	$	27,224	$	28,335		(4	)	Lower operating income and higher effective income tax rate, partly offset by higher AFUDC
Discontinued operations		—		(755	)	NM		Increase in reserve in the second quarter of 2005 for higher arbitration costs relating to HEIPC

Net income	$	27,224	$	27,580		(1	)

Basic earnings (loss) per common share–
Continuing operations	$	0.34	$	0.35		(3	)
Discontinued operations		—		(0.01	)	NM

	$	0.34	$	0.34		—		See explanation for income (loss) above and weighted-average number of common shares outstanding below


Weighted-average number of common shares outstanding		81,100		80,814		—		Issuances of shares under stock option and non-employee director plans


(in thousands, except per share amounts)	Six months ended June 30					% change	Primary reason(s) for significant change*
(in thousands, except per share amounts)	2006		2005			% change	Primary reason(s) for significant change*
Revenues	$	1,179,931	$	994,890		19	Increases for the electric utility and bank segments, slightly offset by a decrease for the “other” segment
Operating income		129,880		118,120		10	Increases for the electric utility and the bank segments, partly offset by a decrease for the “other” segment
Income (loss) from:
Continuing operations	$	59,561	$	52,430		14	Higher operating income and AFUDC, partly offset by higher “interest expense—other than bank” and a higher effective income tax rate
Discontinued operations		—		(755	)	NM	Increase in reserve in the second quarter of 2005 for higher arbitration costs relating to HEIPC

Net income	$	59,561	$	51,675		15

Basic earnings (loss) per common share–
Continuing operations	$	0.73	$	0.65		12
Discontinued operations		—		(0.01	)	NM

	$	0.73	$	0.64		14	See explanation for income (loss) above and weighted-average number of common shares outstanding below


Weighted-average number of common shares outstanding		81,041		80,741		—	Issuances of shares under stock option and non-employee director plans

NM Not meaningful.

*	Also, see segment discussions that follow.

Dividends

On August 1, 2006, HEI’s Board maintained the quarterly dividend of $0.31 per common share. The payout ratio for 2005 and the first six months of 2006 was 79% and 85% (payout ratio of 78% and 85% 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 and that cash flows should support an increase before it considers increasing the common stock dividend above its current level.

Economic conditions

Note: The statistical data in this section is from public third party sources (e.g., Department of Business, Economic Development and Tourism (DBEDT), U.S. Census Bureau and Bloomberg).

Because HEI’s core businesses provide local electric utility and banking services, HEI’s operating results are significantly influenced by the strength of Hawaii’s economy. The state’s economic growth, which is fueled by the two largest components of Hawaii’s economy – tourism and the federal government, was 3.2% in 2005. State economists forecast growth of 3.0% for 2006.

According to the latest available data, Hawaii ranked fifth among the states in its receipt of federal government expenditures per capita. For the federal fiscal year ended September 30, 2004 (latest available data), total federal government expenditures in Hawaii, including military expenditures, were $12.2 billion or $9,651 per capita, increasing 8% and 7%, respectively, over fiscal year 2003. Military spending, which is 39% of federal expenditures in Hawaii, increased 6% in fiscal year 2004 compared to fiscal year 2003.

Tourism is widely acknowledged as a significant component of Hawaii’s economy. 2005 was a record year for tourism in Hawaii, with visitor days exceeding the 2004 record by 6.6%. Visitor expenditures were $11.8 billion in 2005, which is an 8.7% increase from 2004. State economists expect continued growth in 2006 with projected increases of 3.3% in visitor days and 4.7% in visitor expenditures. Visitor days and expenditures were up 2.8% and 6.6%, respectively, for the first five months of 2006 compared to the same period in 2005.

The real estate and construction industries in Hawaii also influence HEI’s core businesses. The Oahu housing market is stabilizing with sales coming off their record levels and inventory returning to more normal levels. The number of sales for the first half of 2006 decreased 8.3% compared to the same period last year, reflecting a stabilizing market. The median home price on Oahu was $639,000 in June 2006 compared to the median of $593,300 in June 2005, but down from a median home price of $650,000 in March 2006.

The construction industry continues to be healthy, indicated by a 19% increase in building permits for the first five months of 2006 compared with the same period last year. However, the rate of increase slowed in the last few months. Local economists forecast a gradual deceleration of growth in residential construction over the next few years due to declining affordability, rising construction costs and interest rate increases. However, it is expected that increased military and commercial construction will be stabilizing factors.

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

Management also monitors (1) oil prices because of their impact on the rates the utilities charge for electricity and the potential effect of increased prices of electricity on usage, and (2) interest rates because of their potential impact on ASB’s earnings, HEI’s and HECO’s cost of capital, pension costs and HEI’s stock price. Geopolitical fallout from Iran’s renewed nuclear program, escalating violence in the Middle East and news of explosions on Nigerian pipelines pushed crude oil prices higher. The average fuel oil cost per barrel for the electric utilities increased 33% and 35% for the three and six months ended June 30, 2006, respectively, compared to the same periods in 2005. On July 27, 2006, crude oil futures closed at $74.54 per barrel.

The 10-year Treasury yield was 5.15% at the end of the second quarter of 2006 compared to 4.86% at the end of the first quarter of 2006. The spread between the 10-year and 2-year Treasuries was (0.04)% as of July 13, 2006, compared to spreads of (0.01)% as of June 30, 2006, 0.04% as of March 31, 2006 and (0.02)% as of December 31, 2005.

“Other” segment


	Three months ended June 30						% change	Primary reason(s) for significant change
(in thousands)	2006			2005			% change	Primary reason(s) for significant change
Revenues	$	(1,544	)	$	586		NM	Unrealized loss of $2.0 million on Hoku shares (see Note 11 of HEI’s “Notes to Consolidated Financial Statements”) and a $0.1 million unrealized loss on a venture capital investment, which also holds Hoku shares
Operating loss		(5,276	)		(3,400	)	NM	Loss on Hoku shares and higher retirement benefit expense, partly offset by lower stock-based compensation expense
Net loss		(6,280	)		(4,861	)	NM	See explanation for operating loss and lower income tax benefit primarily due to the resolution of audit issues with the Internal Revenue Service in 2005, partly offset by lower interest expense due to lower rates and average balance and prior year interest on tax issues

	Six months ended June 30						% change	Primary reason(s) for significant change
(in thousands)	2006			2005			% change	Primary reason(s) for significant change
Revenues	$	(1,652	)	$	1,215		NM	Net unrealized and realized loss of $2.6 million on Hoku shares (see Note 11 of HEI’s “Notes to Consolidated Financial Statements”) and a $0.1 million unrealized loss on a venture capital investment, which also holds Hoku shares
Operating loss		(8,720	)		(7,288	)	NM	Loss on Hoku shares and higher retirement benefit expense, partly offset by lower stock-based compensation expense
Net loss		(11,758	)		(10,912	)	NM	See explanation for operating loss and lower income tax benefit primarily due to the resolution of audit issues with the Internal Revenue Service in 2005, partly offset by lower interest expense due to lower rates and average balance and prior year interest on tax issues

NM Not meaningful.

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., which was previously a maritime freight transportation company that ceased operations in 1999 and now is largely inactive; HEI and HEIDI, which are both holding companies; and eliminations of intercompany transactions.

Commitments and contingencies

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

Recent accounting pronouncements and interpretations

See Note 9 of HEI’s “Notes to Consolidated Financial Statements.”

FINANCIAL CONDITION

Liquidity and capital resources

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, lines of credit and bank borrowings, is adequate to maintain sufficient liquidity to fund the Company’s 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, 2006				December 31, 2005
Short-term borrowings	$	296	12	%	$	142	6	%
Long-term debt, net		1,033	40			1,143	45
Preferred stock of subsidiaries		34	1			34	1
Common stock equity		1,205	47			1,217	48

	$	2,568	100	%	$	2,536	100	%

As of July 31, 2006, the Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HEI securities were as follows:


	S&P	Moody’s
Commercial paper	A-2	P-2
Medium-term notes	BBB	Baa2

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.

HEI’s overall S&P corporate credit rating is BBB/Negative/A-2.

The rating agencies use a combination of qualitative measures (i.e., assessment of business risk that incorporates an analysis of the qualitative factors such as management, competitive positioning, operations, markets and regulation) as well as quantitative measures (e.g., cash flow, debt, interest coverage and liquidity ratios) in determining the ratings of HEI securities. In May 2006, S&P affirmed its corporate credit ratings of HEI and maintained its negative outlook. 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).” S&P indicated that “credit supportive action by the company as well as responsive rate treatment would lead to ratings stability.” See “Electric Utilities—Liquidity and capital resources” below. In addition, S&P ranks business profiles from “1” (strong) to “10” (weak). There was no change in HEI’s business profile rank of “6”. Moody’s maintains a stable outlook for HEI.

As of June 30, 2006, $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 plans to sell Series D Notes under the medium-term note program in the third quarter of 2006 and use the proceeds to reduce its outstanding commercial paper. Following this reduction, HEI’s commercial paper outstanding is expected to increase through the remainder of 2006, as a result of HECO’s plans to suspend its dividend to HEI in the second half of 2006. The decrease in HECO’s dividend will be partly offset by the increase in ASB’s dividend to HEI. See “Electric Utilities—Liquidity and capital resources” and “Bank—Liquidity and capital resources” below.

HEI utilizes short-term debt, principally commercial paper, to support normal operations and for other temporary requirements. HEI also periodically makes short-term loans to HECO to meet HECO’s cash requirements, including for loans by HECO to HELCO and MECO. HEI had an average outstanding balance of commercial paper for the first six months of 2006 of $72 million and had $133 million outstanding as of June 30, 2006. Management believes that if HEI’s commercial paper ratings were to be downgraded, it may be more difficult to sell commercial paper under current market conditions.

Effective April 3, 2006, HEI entered into a revolving unsecured credit agreement establishing a line of credit facility of $100 million, with a letter of credit sub-facility, expiring on March 31, 2011, with a syndicate of eight financial institutions. Any draws on the facility bear interest, at the option of HEI, at the “Adjusted LIBO Rate” plus 50 basis points or the greater of (a) the “Prime Rate” and (b) the sum of the “Federal Funds Rate” plus 50 basis points, as defined in the agreement. Annual fees on undrawn commitments are 10 basis points. The agreement contains provisions for revised pricing in the event of a ratings change. For example, a ratings downgrade of HEI’s Senior Debt Rating (e.g., from BBB/Baa2 to BBB-/Baa3 by S&P and Moody’s, respectively) would result in a commitment fee increase of 2.5 basis points and an interest rate increase of 10 basis points on any drawn amounts. On the other hand, a ratings upgrade (e.g., from BBB/Baa2 to BBB+/Baa1) would result in a commitment fee decrease of 2 basis points and an interest rate decrease of 10 basis points on any drawn amounts. The agreement does not contain clauses that would affect access to the lines by reason of a ratings downgrade, nor does it have broad “material adverse change” clauses. However, the agreement does contain customary conditions which must be met in order to draw on it, including compliance with its covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HEI). In addition to customary defaults, HEI’s failure to maintain its financial ratio, as defined in its agreement, or meet other requirements will result in an event of default. For example, under its agreement, it is an event of default if HEI fails to maintain a nonconsolidated “Capitalization Ratio” (funded debt) of 50% or less (ratio of 26% as of June 30, 2006) and “Consolidated Net Worth” of $850 million (Net Worth of $1.3 billion as of June 30, 2006), if there is a “Change in Control” of HEI, if any event or condition occurs that results in any “Material Indebtedness” of HEI being subject to acceleration prior to its scheduled maturity, if any “Material Subsidiary Indebtedness” actually becomes due prior to its scheduled maturity, or if ASB fails to remain well capitalized and to maintain specified minimum capital ratios.

Also effective April 3, 2006, HEI entered into a $75 million bilateral revolving unsecured credit agreement with Merrill Lynch Bank USA, which expires on December 27, 2006. Any draws on the facility bear interest, at the option of HEI, at the “Adjusted LIBO Rate” plus 57.5 basis points or the greater of (a) the “Prime Rate” and (b) the sum of the “Federal Funds Rate” plus 50 basis points, as defined in the agreement. Under this agreement, a ratings downgrade from BBB/Baa2 to BBB-/Baa3 by S&P and Moody’s, respectively, would result in a 15 basis point increase in interest rates, and a ratings upgrade to BBB+/Baa1 would result in a 7.5 basis point decrease in interest rates. Conditions precedent to drawing on the line and events of default are similar to HEI’s $100 million 5-year revolving unsecured credit agreement.

HEI’s credit facilities, totaling $175 million, are maintained to support the issuance of commercial paper, but also may be drawn for general corporate purposes. These facilities replaced HEI’s four bilateral bank lines of credit totaling $80 million, which were terminated concurrently with the effectiveness of the new facilities. The Company used the new facilities to support the issuance of commercial paper to refinance its $100 million of Series C medium-term notes, which matured on April 10, 2006. As of July 31, 2006, the $175 million of credit facilities were undrawn.

For the first six months of 2006, net cash provided by operating activities of consolidated HEI was $148 million. Net cash used in investing activities for the same period was $166 million primarily due to the purchases of investment securities and net increase in loans receivable at ASB and HECO’s consolidated capital expenditures, partly offset by repayments of mortgage-related securities. Net cash provided by financing activities during this period was $28 million as a result of several factors, including net increases of short-term borrowings and other borrowings, partly offset by repayment of long-term debt, a net decrease in deposit liabilities 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.

ELECTRIC UTILITIES

RESULTS OF OPERATIONS


(dollars in thousands, except per barrel amounts)	Three months ended June 30				% change		Primary reason(s) for significant change
(dollars in thousands, except per barrel amounts)	2006		2005		% change		Primary reason(s) for significant change
Revenues	$	503,967	$	429,730	17		Higher fuel oil and purchased energy fuel costs, the effects of which are generally passed on to customers through energy cost adjustment clauses ($70 million, including related revenue taxes) and HECO interim rate relief ($10 million), partly offset by lower KWH sales ($8 million) and lower DSM lost margins and shareholder incentives ($1M) (See “Most recent rate requests-HECO” below for a discussion of the energy cost adjustment clauses.)
Expenses
Fuel oil		192,314		148,775	29		Higher fuel oil costs, partly offset by less KWHs generated

Purchased power		122,438		106,369	15		Higher fuel costs, partly offset by less KWHs purchased

Other		149,369		131,939	13		Higher other operation and maintenance expenses ($9 million), depreciation ($2 million), and taxes, other than income taxes ($7 million)

Operating income		39,846		42,647	(7	)	Lower KWH sales and DSM lost margins and shareholder incentives and higher expenses, partly offset by HECO interim rate relief

Net income		17,286		19,644	(12	)	Lower operating income and higher interest expense due to higher short-term borrowings average balance and increased short-term interest rates, partly offset by higher AFUDC

Kilowatthour sales (millions)		2,460		2,519	(2	)	Generally cooler, less humid weather and customer conservation, partly offset by new load growth

Oahu cooling degree days (CDD)		1,081		1,471	(27	)

Average fuel oil cost per barrel	$	68.78	$	51.90	33


(dollars in thousands, except per barrel amounts)	Six months ended June 30				% change		Primary reason(s) for significant change
(dollars in thousands, except per barrel amounts)	2006		2005		% change		Primary reason(s) for significant change
Revenues	$	979,023	$	804,505	22		Higher fuel oil and purchased energy fuel costs, the effects of which are generally passed on to customers through energy cost adjustment clauses ($147 million, including related revenue taxes), HECO interim rate relief ($19 million) and higher KWH sales at HELCO and MECO ($5 million), partly offset by lower KWH sales at HECO ($1 million) and lower DSM lost margins and shareholder incentives ($2M) (See “Most recent rate requests-HECO” below for a discussion of the energy cost adjustment clauses.)
Expenses
Fuel oil		367,652		264,401	39		Higher fuel oil costs and more KWHs generated

Purchased power		240,158		207,585	16		Higher fuel costs, partly offset by lower capacity charges and less KWHs purchased

Other		285,787		258,266	11		Higher other operation and maintenance expenses ($9 million), depreciation ($3 million), and taxes, other than income taxes ($15 million)

Operating income		85,426		74,253	15		HECO interim rate relief and lower capacity charges, partly offset by lower KWH sales at HECO and higher expenses and lower DSM lost margins and shareholder incentives

Net income		38,274		32,029	19		Higher operating income and AFUDC, partly offset by higher interest expense due to higher short-term borrowings average balance and increased short-term interest rates
Kilowatthour sales (millions)		4,850		4,866	—		Generally cooler, less humid weather and customer conservation, partly offset by new load growth
Oahu cooling degree days (CDD)		1,854		2,251	(18	)
Average fuel oil cost per barrel	$	66.20	$	48.96	35

See “Economic conditions” in the “HEI Consolidated” section above.

Results – three months ended June 30, 2006

Operating income for the second quarter of 2006 decreased 7% from the same period in 2005 due primarily to lower kilowatthour (KWH) sales, lower DSM lost margins and shareholder incentives and higher expenses, partly offset by interim rate relief granted by the PUC to HECO in late September 2005. KWH sales in the second quarter of 2006 decreased 2.3% from the same period in 2005, primarily due to generally cooler, less humid weather and customer conservation partially in response to the higher cost per KWH due to rising fuel prices. The electric utilities expect this trend to continue as fuel prices remain high. These factors were partly offset by new load growth (i.e., increase in number of customers and new construction). Other operation expense increased 15% primarily due to higher retirement benefits expense, higher production operations expense (including expenses incurred to sustain or increase generating unit availability and lease rent expense for distributed generation units on Oahu) and higher demand-side management expenses. Pension and other postretirement benefit expenses for the electric utilities increased $2.3 million over the same period in 2005 primarily due to the impact of the recognition of investment losses from prior years and the adoption of a 25 basis points lower discount rate as of December 31, 2005 by the HEI Pension Investment Committee. Maintenance expense increased by 13% due to higher production

maintenance expense (primarily due to higher steam generation station maintenance) and transmission and distribution maintenance expense (primarily due to higher vegetation management and distribution line maintenance). Other operations and maintenance expenses also include increased staffing and other costs to support the increased level of peak demand that has occurred over the past five years, reliability, customer service and energy efficiency programs. Higher depreciation expense was attributable to additions to plant in service in 2005 (including HECO’s New Kuahua Substation, Mokuone Substation 46kV and 12kV line extensions, an office building air conditioning replacement and HELCO’s Keahole power plant noise mitigation measures).

Results – six months ended June 30, 2006

Operating income for the first six months of 2006 increased 15% from the same period in 2005 due primarily to interim rate relief granted by the PUC to HECO in late September 2005 and lower purchase power capacity charges due primarily to lower availability caused by scheduled major maintenance by an IPP, which was not performed in 2005, partly offset by higher expenses and lower DSM lost margins and shareholder incentives. KWH sales in the first six months of 2006 decreased 0.3% from the same period in 2005, primarily due to generally cooler, less humid weather and customer conservation partially in response to the higher cost per KWH, partly offset by new load growth (i.e., increase in number of customers and new construction). The electric utilities expect their full-year 2006 KWH sales to be lower than their 2005 KWH sales. Other operation expense increased 8% primarily due to higher retirement benefits expense, higher production operations expense (including expenses incurred to sustain or increase generating unit availability and lease rent expense for distributed generation units on Oahu) and higher demand-side management expenses. Pension and other postretirement benefit expenses for the electric utilities increased $4.5 million over the same period in 2005 primarily due to the impact of the recognition of investment losses from prior years and the adoption of a 25 basis points lower discount rate as of December 31, 2005 by the HEI Pension Investment Committee. Maintenance expense increased by 4% due to higher production maintenance expense (primarily due to higher steam generation station maintenance expense, partly offset by lower generating unit overhaul expense) and transmission and distribution maintenance expense (primarily due to higher distribution line maintenance). Higher depreciation expense was attributable to additions to plant in service in 2005 as described above.

The trend of increased O&M expenses is expected to continue as the electric utilities expect (1) higher demand-side management expenses (that are generally passed on to customers through a surcharge, including additional expenses for programs that have been approved pursuant to an interim decision and order in an energy efficiency DSM Docket) and integrated resource planning expenses, (2) higher employee benefit expenses, primarily for retirement benefits, and (3) higher production expenses, primarily to support the increased level of peak demand that has occurred over the past five years. Also, since May 26, 2006, HECO has discontinued it’s recovery of lost margins and shareholder incentives for its DSM programs until further order by the PUC, which results in reduced revenues.

As a result of load growth on Oahu and other factors, there currently is an increased risk to generation reliability. Existing units are running harder, resulting in more frequent and more extensive maintenance, at times requiring temporary shut downs of these units. Generation reserve margins during peak periods are lower than considered desirable in light of these circumstances. The electric utilities have taken a number of steps to mitigate the risk of outages, including securing additional purchased power, adding distributed generation at some substations and encouraging energy conservation. The marginal costs of supplying growing demand, however, are increasing because of the decreasing reserve margin situation, and the trend of cost increases is not likely to ease. Increased O&M expense was one of the reasons HECO filed a request with the PUC in November 2004 to increase base rates. In late September 2005, HECO received interim rate relief (see “Most recent rate requests”).

Competition

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 stated purpose of this proceeding is to evaluate competitive bidding as a mechanism for acquiring or building new generating capacity in Hawaii.

The current parties in the proceeding include the Consumer Advocate, HECO, HELCO, MECO, Kauai Island Utility Cooperative and Hawaii Renewable Energy Alliance (HREA), a renewable energy 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 were filed in March through August 2005. The PUC held panel hearings in December 2005. In May 2006, all of the parties, except HREA, jointly filed a proposed competitive bidding framework incorporating areas of agreement in on-going settlement discussions. In June 2006 briefs addressing any areas of disagreement and post-hearing questions posed by the PUC were filed and oral arguments were presented.

On June 30, 2006 the PUC issued a D&O in this proceeding, which included a proposed framework to govern competitive bidding. The D&O contained modifications to the framework proposed by the parties and stated (1) the final decision on whether to use competitive bidding for a particular project will be made by the PUC during its review of the utility’s integrated resource plan (IRP), (2) exemption from the framework would be granted for cooperatively-owned utilities, for three pending projects (HECO’s CT-1, HELCO’s ST-7 and MECO’s M-18 projects), and specifically identified offers to sell energy on an as-available basis by non-fossil fuel producers that are under review by an electric utility at the time this framework is adopted, (3) waivers will be granted where bidding will be unproductive or will conflict with the utility’s obligation to bring resources on-line timely and at reasonable cost, (4) the parties are required to submit briefs that address issues regarding Qualifying Facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA), (5) the utility is required to submit a report on the cost of parallel planning upon the PUC’s request and the utility must submit a code of conduct to the PUC for approval prior to the commencement of any competitive bid process under this framework, (6) the utility is required to consider the effects on competitive bidding of not allowing site access to bidders and present reasons for not allowing site access to bidders when the utility has not chosen to offer a site to a third party, (7) the utility is required to select an independent observer from a list approved by the PUC whenever the utility or its affiliate seeks to advance a project proposal (i.e., in competition with those offered by bidders) in response to a need that is addressed by its Request for Proposal or when the PUC otherwise determines, (8) in evaluating the utility’s bid, the independent observer is required to address the probability that later costs will exceed the utility’s original bid, (9) the utility may consider a bid from its affiliate if the PUC determines, prior to commencement of the competitive bidding process, that the affiliate has no advantage due to its past or present relationship to the utility, or the affiliate is a qualifying facility exercising its mandatory sales rights under PURPA, and (10) the utility is required to submit a proposed tariff containing procedures for interconnection and transmission upgrades within 90 days. Management cannot currently predict the ultimate effect of this proceeding on the ability of the electric utilities to acquire or build additional generating capacity in the future.

Distributed generation proceeding. In October 2003, the PUC opened a DG proceeding to determine DG’s potential benefits to and impact on Hawaii’s electric distribution systems and markets and to develop policies and a framework for DG projects deployed in Hawaii.

On January 27, 2006, the PUC issued its D&O in the DG proceeding. In the D&O, the PUC indicated that its policy is to promote the development of a market structure that assures DG is available at the lowest feasible cost, DG that is economical and reliable has an opportunity to come to fruition and DG that is not cost-effective does not enter the system.

With regard to DG ownership, the D&O affirmed the ability of the electric utilities to procure and operate DG for utility purposes at utility sites. The PUC also indicated its desire to promote the development of a competitive market for customer-sited DG. In weighing the general advantages and disadvantages of allowing a utility to provide DG services on a customer’s site, the PUC found that the “disadvantages outweigh the advantages.” However, the PUC also found that the utility “is the most informed potential provider of DG” and it would not be in the public interest to exclude the electric utilities from providing DG services at this early stage of DG market development.

Therefore, the D&O allows the utility to provide DG services on a customer-owned site as a regulated service when (1) the DG resolves a legitimate system need, (2) the DG is the least cost alternative to meet that need, and (3) it can be shown that, in an open and competitive process acceptable to the PUC, the customer operator was unable to find another entity ready and able to supply the proposed DG service at a price and quality comparable to the utility’s offering.

The D&O also requires the electric utilities to file tariffs, establish reliability and safety requirements for DG, establish a non-discriminatory DG interconnection policy, develop a standardized interconnection agreement to streamline the DG application review process, establish standby rates based on unbundled costs associated with providing each service (i.e., generation, distribution, transmission and ancillary services), and establish detailed affiliate requirements should the utility choose to sell DG through an affiliate. The electric utilities filed their proposed modifications to existing DG interconnection tariffs for PUC approval in July 2006, and requested an extension until August 28, 2006 to file their proposed unbundled standby rates.

On March 1, 2006, the electric utilities filed a Motion for Clarification and/or Partial Reconsideration (DG Motion) requesting that the PUC clarify how the three conditions under which electric utilities are allowed to provide regulated DG services at customer-owned sites will be administered, in order to better determine the impacts the conditions may have on the electric utilities’ DG plans. On April 6, 2006, the PUC issued its decision on the electric utilities’ DG Motion. The PUC provided clarification to the conditions under which the electric utilities are allowed to provide regulated DG services (e.g., the utilities can use a portfolio perspective—a DG project aggregated with other DG systems and other supply-side and demand-side options—to support a finding that utility-owned customer-sited DG projects fulfill a legitimate system need, and the economic standard of “least cost” in the order means “lowest reasonable cost” consistent with the standard in the IRP framework), and affirmed that the electric utility has the responsibility to demonstrate that it meets all applicable criteria included in the D&O in its application for PUC approval to proceed with a specific DG project.

The electric utilities are currently evaluating several potential DG and CHP projects. If a decision is made to pursue a specific project, an application requesting project approval will be filed with the PUC. In July 2006, MECO filed an application for approval of an agreement for the installation of a CHP system on the island of Lanai.

Most recent rate requests

The electric utilities initiate PUC proceedings from time to time to request electric rate increases to cover rising operating costs and the cost of plant and equipment, including the cost of new capital projects to maintain and improve service reliability. As of July 31, 2006, 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). However, the ROACE used for purposes of the interim rate increase in HECO’s current rate case was 10.70%.

For the 12 months ended June 30, 2006, the simple average ROACEs (calculated under the rate-making method and reported to the PUC semi-annually) for HECO, HELCO and MECO were 8.09%, 5.44% and 9.74%, respectively. HECO’s actual ROACE is significantly lower than its allowed ROACE primarily because of increased O&M expenses, which are expected to continue and are likely to result in HECO seeking rate relief more often than in the past. The interim rate relief granted to HECO by the PUC in September 2005 (see below) was based in part on increased costs of operating and maintaining HECO’s system. 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 the PUC grants HELCO rate relief in the rate case commenced by HELCO in May 2006 (see below).

As of July 31, 2006, the 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). However, the ROR used for purposes of the interim D&O in the current HECO rate case is 8.66%. For the 12 months ended June 30, 2006, the simple average RORs (calculated under the rate-making method and reported to the PUC semi-annually) for HECO, HELCO and MECO were 6.84%, 5.59% and 7.91%, respectively.

If the utilities are required to record significant charges to accumulated other comprehensive income (AOCI) related to a minimum liability for retirement benefits, the electric utilities’ RORs would increase and could impact the rates the electric utilities are allowed to charge, which may ultimately result in reduced revenues and lower earnings. In December 2005, the electric utilities submitted a request to the PUC for approval to record as a regulatory asset and include in rate base the amount that would otherwise be charged to AOCI and reduce stockholder’s equity. If their request is granted, the electric utilities’ stockholder’s equity and rate base would not be affected since charges to AOCI would not be made to record a minimum pension liability and their returns on equity and rate base and financial ratios would thus not be adversely affected.

HECO. In November 2004, HECO filed a request with the PUC to increase base rates 9.9%, or $99 million in annual base revenues, based on a 2005 test year, a 9.11% ROR and an 11.5% ROACE. The requested increase included transferring the cost of existing DSM programs from a surcharge line item on electric bills into base electricity charges. HECO also requested approval and/or modification of its existing and proposed DSM programs, and associated utility incentive mechanism. Excluding the surcharge transfer amount, the requested net increase to customers was 7.3%, or $74 million.

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 (EE DSM 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 DOD, 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 (and in September 2005 made the County of Kauai a participant), provided their participation is limited solely to the issues dealing with statewide energy policies. In March 2006, the PUC informed the parties that it would involve the EPA and its consultants in an advisory capacity in this docket and amended the procedural schedule to include the submission of reports by the EPA and its consultants on the issues in this proceeding. Simultaneous statements of position were

filed by the parties in June 2006. The EPA submitted its comments in July 2006, and the parties will respond to the EPA comments in August 2006, prior to the panel hearings scheduled for late August 2006. See “Other regulatory matters—Demand-side management programs” below for additional information on this docket and a discussion of the PUC’s Interim D&O issued on April 26, 2006.

In September 2005, HECO, the Consumer Advocate and the DOD reached agreement among themselves on most of the issues in the rate case proceeding, subject to PUC approval. The remaining significant issue among the parties was the appropriateness of including in rate base approximately $50 million related to HECO’s prepaid pension asset, net of deferred income taxes.

Later in September 2005, the PUC issued its interim D&O (with tariff changes effective September 28, 2005 and amounts collected refundable, with interest, to ratepayers to the extent they exceed the amount approved in the final D&O). For purposes of the interim D&O, the PUC included HECO’s prepaid pension asset in rate base (with a rate increase impact of approximately $7 million).

The following amounts were included in HECO’s rebuttal, the Consumer Advocate’s and the DOD’s testimonies and exhibits (as adjusted to exclude the transferred surcharge amount of $12 million); the settlement agreement; and the PUC’s interim D&O:


	Pre-Settlement						HECO (per settlement)		Interim increase¹
(dollars in millions)	HECO rebuttal		Consumer Advocate		Department of Defense		HECO (per settlement)		Interim increase¹
Net additional revenues ²	$	51	$	11	$	7	$	42	$	41
ROACE (%)		11		8.5-10		9		10.7		10.7
ROR (%)		8.83		7.85		7.71		8.66		8.66
Average rate base	$	1,109	$	1,065	$	1,062	$	1,109	$	1,109

¹	Effective September 28, 2005, subject to refund with interest pending the final outcome of the case.

²	Excludes $12 million transferred from a surcharge to base rates for existing energy efficiency programs.

The adoption of revenue, expense, rate base and cost of capital amounts (including the ROACE and ROR) for purposes of an interim rate increase does not commit the PUC to accept any such amounts in its final D&O.

On June 19, 2006, the PUC issued an order in HECO’s pending rate case, indicating that the record in the pending case has not been developed for the purpose of addressing the factors in Act 162, signed into law by the Governor of Hawaii on June 2, 2006. See “Energy cost adjustment clauses” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.” The PUC’s order requested the parties in the rate case proceeding to meet informally to determine a procedural schedule to address the issues relating to HECO’s ECAC that are raised by Act 162. The parties in the rate case proceeding are HECO, the Consumer Advocate, and the DOD.

HELCO. In May 2006, HELCO filed a request with the PUC to increase base rates by $30 million, or 9.24% in annual base revenues, based on a 2006 test year, an 8.65% ROR, a 11.25% ROACE and a $369 million average rate base. HELCO’s application includes a proposed new tiered rate structure, which would enable most residential users to see smaller increases in the range of 3% to 8%. The tiered rate structure is designed to minimize the increase for residential customers using less electricity and is expected to encourage customers to take advantage of solar water heating programs and other energy management options. The proposed rate increase would pay for improvements made to increase reliability, including transmission and distribution line improvements and the two generating units at the Keahole power plant (CT-4 and CT-5). The application requests the continuation of HELCO’s ECAC.

The PUC held public hearings on HELCO’s application in June 2006. The Keahole Defense Coalition has filed a motion to participate in this proceeding, and a nonprofit organization that promotes conservation and the use of renewable resources filed a motion to intervene in this proceeding. The ECAC provisions of Act 162 will be addressed in this rate case. The earliest that any increase, if allowed, may go into effect is expected to be in early 2007.

Other regulatory matters

For information about the “Avoided cost generic docket,” see page 67 of HEI’s and HECO’s 2005 Form 10-K. Subsequently, the parties requested and in June 2006 were granted an extension until November 30, 2006 to file the required information with the PUC.

Demand-side management programs. The following updates the “Demand-side management programs” discussions on pages 66 to 67 of HEI’s and HECO’s 2005 Form 10-K.

In October 2001, HECO and the Consumer Advocate finalized agreements, subject to PUC approval, for the continuation of HECO’s three commercial and industrial DSM programs and two residential DSM programs until HECO’s next rate case. These agreements were in lieu of HECO continuing to seek approval of new 5-year DSM programs and provided that DSM programs to be in place after HECO’s next rate case would be determined as part of the case. Under the agreements, HECO agreed to cap the recovery of lost margins and shareholder incentives if such recovery would cause HECO to exceed its current “authorized return on rate base” (i.e. the rate of return on rate base found by the PUC to be reasonable in the most recent rate case for HECO). HECO also agreed it would not pursue the continuation of lost margins recovery and shareholder incentives through a surcharge mechanism in future rate cases. At the time of the agreement, HECO indicated to the Consumer Advocate that it planned to seek alternative incentive mechanisms for DSM programs in its rate case. In November 2001, the PUC issued orders that, subject to certain reporting requirements and other conditions, approved the agreements regarding the temporary continuation of HECO’s five existing DSM programs until HECO’s next rate case.

In November 2004, HECO filed a request for a rate increase and approval and/or modification of its existing and proposed DSM programs, and associated utility incentive mechanism. 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 EE DSM docket. The bifurcation order allowed HECO to temporarily continue, in the manner currently employed, its existing three commercial and industrial DSM programs and two residential DSM programs, until further order by the PUC.

As a result of the bifurcation order in HECO’s rate case, HECO has been continuing its existing DSM programs and cost recovery mechanisms, including the recovery of program costs, and shareholder incentives and lost margins for its energy efficiency DSM programs through a surcharge mechanism, pending the resolution of the EE DSM Docket. In the EE DSM Docket, HECO requested PUC approval, on an interim basis, for certain modifications to its existing energy efficiency DSM programs and a new interim DSM program (Interim DSM Proposals). HECO did not request shareholder incentives and lost margins for its proposed new interim DSM program, but did so for the modifications to its existing energy efficiency programs. On January 10, 2006, the Consumer Advocate filed comments on HECO’s Interim DSM Proposals, which included an objection to the continued recovery of shareholder incentives and lost margins for the existing energy efficiency DSM programs as well as for the modifications. HECO filed its response to the Consumer Advocate’s comments on January 31, 2006, reaffirming its position that the continuation of shareholder incentives and lost margins for its existing energy efficiency DSM programs is appropriate and conforms with the PUC’s order allowing the continuation of its existing DSM programs pending the resolution of

the EE DSM Docket. The issues of whether DSM incentive mechanisms are appropriate to encourage the implementation of DSM programs, the appropriate mechanism(s) for such DSM incentives, and whether HECO’s proposed DSM utility incentive is reasonable are included in the Statement of Issues in the Prehearing Order in the EE DSM Docket.

On April 26, 2006, the PUC issued an Interim Decision and Order (Interim D&O) approving HECO’s request to modify its existing DSM programs and implement its proposed interim DSM program. However, the PUC also ordered HECO’s recovery of lost margins and shareholder incentives for its DSM programs be discontinued within 30 days of the Interim D&O (i.e., by May 26, 2006), until further order by the PUC. Lost margins and shareholder incentives are estimated and recorded in the year earned, and collected from ratepayers in the current year (lost margins) or the following year (shareholder incentives). Revenues that HECO expected to accrue for lost margins and shareholder incentives from May 26, 2006 through the end of 2006 are estimated at $2.1 million, or $1.2 million in after-tax net income.

On May 25, 2006, HECO filed a Motion for Partial Reconsideration of the Interim D&O issued by the PUC on April 26, 2006 to reconsider that part of the Interim D&O that requires HECO to discontinue the accrual of lost margins and shareholder incentives for its existing DSM programs. On June 13, 2006, the PUC replied to the Motion by scheduling a hearing during the week of August 28, 2006 during the time of the panel hearings for the EE DSM Docket, as requested by HECO.

In October 2001, HELCO and MECO had reached similar agreements with the Consumer Advocate regarding the continuation of their DSM programs and filed requests to continue their four existing DSM programs. In November 2001, the PUC issued orders (one of which was later amended) that, subject to certain reporting requirements and other conditions, approved the agreements regarding the temporary continuation of HELCO’s and MECO’s DSM programs until one year after the PUC makes a revenue requirements determination in HECO’s next rate case. Under the orders, however, HELCO and MECO are allowed to recover only lost margins and shareholder incentives accrued through the date that interim rates are established in HECO’s next rate case, but may request to extend the time of such accrual and recovery for up to one additional year. HECO believes that the temporary continuation of HECO’s existing DSM programs, as a result of the bifurcation order in HECO’s rate case, had the effect of postponing the deadline for the recovery of HELCO and MECO’s lost margins and shareholder incentives until resolution of the EE DSM Docket.

Based on the Interim D&O in the EE DSM docket, on May 25, 2006, HELCO and MECO filed a request for a one-year extension for the recovery of HELCO and MECO’s lost margins and shareholder incentives or until final resolution of the EE DSM Docket. HELCO and MECO are awaiting a PUC decision on the one-year extension of their ability to collect lost margins and shareholder incentives. Lost margins and shareholder incentives accrued for HELCO and MECO from May 26, 2006 through June 30, 2006 amounted to $0.2 million and $0.4 million, respectively, and an offsetting reserve was established for such amounts.

Integrated resource planning, requirements for additional generating capacity and adequacy of supply. The PUC issued an order in 1992 requiring the energy utilities in Hawaii to develop IRPs. The goal of integrated resource planning is the identification of demand- and supply-side resources and the integration of these resources for meeting near- and long-term consumer energy needs in an efficient and reliable manner at the lowest reasonable cost. The utilities’ proposed IRPs are planning strategies, rather than fixed courses of action, and the resources ultimately added to their systems may differ from those included in their 20-year plans. Under the PUC’s IRP framework, the utilities are required to submit annual evaluations of their plans (including a revised five-year program implementation schedule) and to submit new plans on a three-year cycle, subject to changes approved by the PUC. Prior to proceeding with the DSM programs, separate PUC approval proceedings must be completed.

The utilities are entitled to recover all appropriate and reasonable integrated resource planning and implementation costs, including the costs of DSM programs, either through a surcharge or through their base rates. Under procedural schedules for the IRP cost proceedings, the utilities can begin recovering their incremental IRP costs in the month following the filing of their actual costs incurred for the year, subject to refund with interest pending the PUC’s final D&O approving recovery of the costs. HELCO and HECO now recover IRP costs through base rates.

The Consumer Advocate has objected to the recovery of $3.2 million (before interest) of the $11.8 million of incremental IRP costs incurred by the utilities during the 1995-2004 period, and the PUC’s decision is pending on this matter. As of June 30, 2006, the amount of revenues, including interest and revenue taxes, that the electric utilities recorded for IRP cost recoveries, subject to refund with interest, amounted to $19 million.

HECO’s IRP. In October 2005, HECO filed its third IRP (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 DG) and central station generation (including a combustion turbine generating unit in 2009 and a possible 180 MW coal unit in 2022). In addition, all existing generating units are currently planned to be operated (future environmental considerations permitting) beyond the 20-year IRP planning period (2006-2025). In June 2006, the PUC granted an environmental group’s motion to intervene in the proceeding and ordered the parties to determine the issues, procedures and schedule for the docket and to file a stipulated procedural order.

In June 2005, HECO filed with the PUC an application for approval of funds to build a new 110 MW simple cycle combustion turbine generating unit at Campbell Industrial Park and an additional 138 kilovolt transmission line to transmit power from the new unit and existing generating units at Campbell Industrial Park to the Oahu electric grid. Plans are for the combustion turbine to be run primarily as a “peaking” unit beginning in 2009, and to burn naphtha or diesel, but will be capable of using biofuels, such as ethanol. On December 15, 2005, HECO signed a contract with Siemens for the right to purchase up to two 110 MW combustion turbine units. The contract allows HECO to terminate the contract at a specified payment amount if necessary combustion turbine (CT) project approvals are not obtained. In April 2006, HECO issued Solicitation of Interest letters to prospective suppliers of ethanol, asking them to indicate their ability to provide ethanol to specifications such as chemical composition and heat generating capacity, for use in a blend of ethanol and naphtha in the new generating unit. After reviewing the responses received, HECO, in consultation with the PUC and the Consumer Advocate, may issue a more detailed request for proposals or enter into direct negotiations with potential providers. The PUC would need to approve any ethanol fuel contract.

Preliminary costs for the new generating unit and transmission line, as well as related substation improvements, are estimated at $137 million. As of June 30, 2006 accumulated project costs for planning, engineering, permitting and AFUDC amounted to $3.3 million. HECO submitted a Final Environmental Impact Statement to the Department of Planning & Permitting of the City and County of Honolulu in July 2006.

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.

The PUC granted an environmental group’s motion to intervene and a neighboring business entity’s motion to participate in the generating unit and transmission line application. The procedural schedule for the proceeding includes hearings in December 2006. For the community benefits application, the only party is the Consumer Advocate, and hearings are scheduled for November 2006.

HELCO’s IRP. In September 1998, HELCO filed its second IRP with the PUC, and updated it in 1999 and 2004. On the supply side, HELCO’s second IRP focused on the planning for generating unit additions after near-term additions. The near-term additions included installing two 20 MW CTs at its Keahole power plant site (which were put into limited commercial operation in May and June 2004) and a PPA with Hamakua Energy Partners, L.P. (HEP) for a 60 MW (net) facility (which was completed in December 2000). HELCO has deferred the retirements of some of its older generating units until the 2030 timeframe, and periodically assesses the cost-effectiveness of the continued operation of those units. HELCO’s current plans are to install an 18 MW heat recovery steam generator (ST-7) in 2009 or earlier. After the installation of ST-7, the target date in HELCO’s updated second IRP for the next firm capacity addition is the 2017 timeframe.

HELCO’s third IRP is required to be filed with the PUC by December 31, 2006.

MECO’s IRP. MECO filed its second IRP with the PUC in May 2000, and updated it in 2004 and 2005. On the supply side, MECO’s second IRP focused on the planning for the installation of approximately 150 MW of additional generation through the year 2020 on the island of Maui, including 38 MW of generation at its Maalaea power plant

site in increments from 2000-2005, 100 MW at its new Waena site in increments from 2007-2018, beginning with a 20 MW combustion turbine in 2007 (currently not planned to be added until 2011), and 10 MW from the acquisition of a wind resource in 2003 (but with MECO actually beginning to purchase 30 MW of wind energy in 2006 from Kaheawa Wind Power, LLC). Approximately 4 MW of additional generation through the year 2020 were included for each of the islands of Lanai and Molokai. MECO completed the installation of a 20 MW increment (the second) at Maalaea in September 2000, and the final increment of 18 MW, which was originally expected to be installed in 2005, is being installed and is expected to be in service by the end of the third quarter of 2006.

MECO’s third IRP is required to be filed with the PUC by October 31, 2006.

Adequacy of supply.

HECO. As a result of load growth and other factors, HECO’s 2005 Adequacy of Supply letter filed in March 2005 concluded that generation reserve margins, although substantial, were lower than is considered desirable on Oahu under the circumstances, and that there was an increased risk to generation reliability. Also, the letter stated that the risk of having generation-related customer outages would be higher if the peak reduction impacts of planned energy efficiency DSM programs, load management programs or CHP installations fall short of achieving their forecasted benefits. This situation is expected to continue if the peak demand continues to grow as forecasted, at least until 2009, which is the earliest HECO expects to be able to install its planned combustion turbine. The letter also indicated that HECO was working on plans to implement a number of potential interim mitigation measures, such as installing portable, leased, distributed 1.6 MW generating units at substations or other sites (nine units totaling 14.8 MW were installed in the fourth quarter of 2005) and initiating a customer demand response program to supplement its load management programs (for which HECO plans to request approval in the third quarter of 2006). HECO did not experience actual generation shortfalls causing customer load shedding in 2005, in part because peak loads were lower than forecast in the second half of 2005.

HECO’s 2006 Adequacy of Supply letter filed in March 2006 indicates that HECO’s latest analysis estimates the reserve capacity shortfall to be between 170 MW and 200 MW in the 2006 to 2009 period, which is significantly larger than the 50 to 70 MW shortfall projected in the 2005 Adequacy of Supply letter. The increase in projected reserve capacity shortfall is largely due to the lower projected availability of existing generating units, and a reduction in the projected impacts from planned peak reduction measures. Generating units may be entirely or partially unavailable to serve load during scheduled overhaul periods and other planned maintenance outages, or when they “trip” or are taken out of operation or their output is “de-rated” due to equipment failure or other causes. While the availability rates for generating units on Oahu have been better than those of comparable units on the U.S. mainland, the availability rates declined in 2002 through 2005. Based on this experience, the manner in which the units must be operated when there is a reserve capacity shortfall, and the increasing ages of the units, HECO expects this situation to continue in the near-term and is forecasting lower availability rates than were used in the 2005 analyses.

To mitigate the projected reserve capacity shortfalls and to increase generating unit availability going forward, HECO is continuing to plan and implement mitigation measures, such as installing additional distributed generators at substations or other sites, seeking approval for additional load management and other demand reduction measures, and pursuing efforts to improve the availability of generating units. HECO will operate at lower than desired reliability levels and take steps to mitigate the reserve capacity shortfall situation until the next generating unit is installed. Until sufficient generating capacity can be added to the system, HECO will experience a higher risk of generation related customer outages. Given the magnitude of the projected reserve capacity shortfall, HECO also will evaluate the need to file an application with the PUC for approval to add more firm capacity (over and above the PUC application filed in June 2005 for a 110 MW simple-cycle combustion turbine at Campbell Industrial Park). HECO did not experience actual generation shortfalls that caused shedding of firm customers in the first quarter of 2006. However, on June 1, 2006, due to the unanticipated loss of three generating units from an IPP and two HECO generating units, HECO shed 29,300 customers in various parts of the island. Power was restored to all customers within four hours. HECO’s system peak loads generally occur in the fourth quarter of the year, and the possibility remains for generation shortfall events in subsequent periods.

HELCO. HELCO’s 2006 Adequacy of Supply letter filed in February 2006 indicated that HELCO’s generation capacity for the next three years, 2006 through 2008, is sufficiently large to meet all reasonably expected demands for service and provide reasonable reserves for emergencies.

MECO. In December 2005, MECO’s Maalaea Unit 13, a 12.34 MW diesel generator suffered an equipment failure and the unit is not expected to be available for service until approximately June 2007. In March 2006 MECO filed its 2006 Adequacy of Supply letter which indicated that MECO’s Maui island system should generally have sufficient installed capacity to meet the forecasted loads. However, in the event of an unexpected outage of the largest unit, until Maalaea Unit 13 returns to service, the Maui island system may not have sufficient capacity. To overcome insufficient reserve capacity situations, MECO plans to implement appropriate mitigation measures, such as optimizing its unit overhaul schedule to minimize load capability shortfalls, coordinating the delivery of supplemental power, as needed, from an IPP and modifying its combined-cycle unit overhaul procedure to allow for the possible operation of the combustion turbine in simple-cycle mode. On April 3, 2006, MECO experienced lower than normal generation capacity due to the unexpected temporary loss of several of its generating units, and issued a request for the public to voluntarily conserve electricity. MECO is in the process of installing an additional 18 MW of capacity, which is expected to be in service by the end of the third quarter of 2006.

Collective bargaining agreements

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

Legislation and regulation

Congress and the State of Hawaii Legislature periodically consider legislation that could have positive or negative effects on the utilities and their customers. For information about legislation and regulation impacting HECO and its subsidiaries, see pages 70 to 72 of HEI’s and HECO’s 2005 Form 10-K. Following are legislation and regulation updates. Also, see “Energy cost adjustment clauses” in Note 5 of HECO’s “Notes to Consolidated Financial Statements” for a discussion of Act 162.

2006 Hawaii State Legislature energy measures. The 2006 Hawaii State Legislature passed energy measures, which were signed into law by the Governor of Hawaii, including the following (in addition to the ECAC provisions of Act 162 discussed above):

Renewable Portfolio Standards (RPS) law. The State RPS law was amended to provide that at least 50% of the RPS targets must be met by electrical energy generated using renewable energy sources such as wind or solar versus from the electrical energy savings from renewable energy displacement technologies (such as solar water heating) or from energy efficiency and conservation programs. The amendment also added provisions for penalties to be established by the PUC if the RPS requirements are not met and criteria for waiver of the penalties by the PUC, if the requirements cannot be met due to circumstances beyond the electric utility’s control. And the amendment extends the date to December 31, 2007 for the PUC to develop and implement a utility rate making structure to provide incentives to encourage electric utilities to use cost effective renewable energy resources.

DSM programs. The PUC was given the authority, if it deems appropriate, to redirect all or a portion of the funds currently collected by the utilities and included in their revenues through the current utility DSM surcharge into a Public Benefits Fund, for the purpose of supporting customer DSM programs approved by the PUC. If the fund is established, the PUC is required to appoint a fund administrator (other than an electric utility or utility affiliate), to operate and manage the programs established under the fund.

Non-fossil fuel purchased power contracts. The PUC will be required to delink the price paid for non-fossil-fuel-generated electricity under future power purchase contracts from the price of fossil fuel, in order to allow utility customers to receive the potential cost savings from non-fossil fuel generation.

Public Utility Holding Company Act of 1935 (1935 Act) and Public Utility Holding Company Act of 2005 (2005 Act). The repeal of the 1935 Act, effective February 8, 2006, eliminated significant federal restrictions on the scope, structure and ownership of electric utilities. Some believe that the repeal will result in increased institutional ownership of and private equity and hedge fund investments in public utilities, increased consolidation in the industry,

more Federal Energy Regulatory Commission (FERC) oversight, and additional diversification by electric utilities. The increased oversight by FERC results in part from the adoption of the 2005 Act, which provides for FERC access to the books and records of utility holding companies and, absent exemptions or waivers, imposes certain record retention and accounting requirements on public utility holding companies. HEI and HECO filed a notification claiming a waiver of such requirements as single-state public utility holding companies. A written notice dated May 26, 2006 was received from FERC confirming the effectiveness of the HEI and HECO waivers. Regulation and oversight of HECO and its subsidiaries by the PUC remain unchanged.

Net energy metering. Hawaii has a net energy metering law, which requires that electric utilities offer net energy metering to eligible customer generators (i.e., a customer generator may be a net user or supplier of energy and will make payment to or receive credit from the electric utility accordingly). The law provides a cap of 0.5% of the electric utility’s peak demand on the total generating capacity produced by eligible customer-generators. The 2004 Legislature amended the net energy metering law by expanding the definition of “eligible customer generator” to include government entities, increasing the maximum size of eligible net metered systems from 10 kilowatts (kw) to 50 kw and limiting exemptions from additional requirements for systems meeting safety and performance standards to systems of 10 kw or less.

The 2005 Legislature amended the net energy metering law, by among other things, authorizing the PUC, by rule or order, to increase the maximum size of the eligible net metered systems and to increase the total rated generating capacity available for net energy metering. In April 2006, the PUC initiated an investigative proceeding on whether the PUC should increase (1) the maximum capacity of eligible customer-generators to more than 50 kw and (2) the total rated generating capacity produced by eligible customer-generators to an amount above 0.5% of an electric utility’s system peak demand. The parties to the proceeding include HECO, HELCO, MECO, Kauai Island Utility Cooperative, a renewable energy organization and a solar vendor organization. The parties are in the process of discussing a procedural schedule for the investigative proceeding. Depending on their magnitude, changes made by the PUC by rule or order could have a negative effect on electric utility sales. Management cannot predict the outcome of the investigative proceeding.

Other developments

Electronic shock absorber (ESA). HECO received a U.S. patent in February 2005 for an ESA that addresses power fluctuations from wind resources. An ESA demonstration system has been installed and is currently being tested at HELCO’s Lalamilo wind farm. HECO has an intellectual property license agreement with S&C Electric Company (S&C), the party constructing the ESA demonstration system. S&C has the right to seek international patents for the design. Management cannot predict the amount of royalties HECO may receive from the sale of ESAs in the future.

Broadband over Power Line (BPL) technology. 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 in 2005. Based on the favorable results of the trial, HECO has proceeded with a pilot in an expanded residential/commercial area in Honolulu, which is expected to run through at least the fourth quarter of 2006. The effort is primarily focused on automatic meter reading, which is aimed at enabling time of use rates for residential and commercial customers. Other BPL-enabled utility applications being evaluated include distribution system line monitoring, residential direct load control and monitoring of distribution substation equipment. HECO is also evaluating broadband information services that might potentially be provided by other service providers.

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.

EarthLink, an internet service-provider, and the City and County of Honolulu will partner in a test to provide free, wireless, broadband access in Chinatown in downtown Honolulu. As part of that Chinatown Pilot project, EarthLink and HECO are negotiating a separate non-binding collaborative agreement to develop and demonstrate a variety of utility applications using WiFi technology, including advanced electric metering and energy conservation initiatives.

This utility applications pilot project is expected to continue for approximately one year, subject to the execution of the City and County of Honolulu and EarthLink Chinatown Pilot Agreement.

Commitments and contingencies

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

Recent accounting pronouncements and interpretations

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

FINANCIAL CONDITION

Liquidity and capital resources

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, lines of credit and bank 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.

HECO’s consolidated capital structure was as follows:


(in millions)	June 30, 2006				December 31, 2005
Short-term borrowings	$	163	8	%	$	136	7	%
Long-term debt		766	38			766	38
Preferred stock		34	2			34	2
Common stock equity		1,048	52			1,039	53

	$	2,011	100	%	$	1,975	100	%

As of July 31, 2006, the Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HECO securities were as follows:


	S&P	Moody’s
Commercial paper	A-2	P-2
Revenue bonds (senior unsecured, insured)	AAA	Aaa
HECO-obligated preferred securities of trust subsidiaries	BBB-	Baa2
Cumulative preferred stock (selected series)	Not rated	Baa3

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 May 2006, S&P affirmed its corporate credit ratings of HECO and its negative outlook. 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).” In response to the PUC’s interim rate decision for HECO, S&P stated, and also reiterated in May 2006, “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 reconsider its negative outlook when the PUC issues its final order. In addition, S&P ranks business profiles from “1” (strong) to “10” (weak). There was no change in HECO’s business profile rank of “5”. Moody’s maintains a stable outlook for HECO.

HECO 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. At June 30, 2006, HELCO and MECO had $50.1 million and $6.5 million, respectively, of short-term borrowings from HECO. HECO had an average outstanding balance of commercial paper for the first six months of 2006 of $144 million and had $163 million of commercial paper outstanding as of June 30, 2006. Management believes that if HECO’s commercial paper ratings were to be downgraded, it may be more difficult for HECO to sell commercial paper under current market conditions.

Effective April 3, 2006, HECO entered into a revolving unsecured credit agreement establishing a line of credit facility of $175 million with a syndicate of eight financial institutions. The agreement has an initial term which expires on March 29, 2007, but will automatically extend to 5 years if the longer-term agreement is approved by the PUC. Any draws on the facility bear interest, at the option of HECO, at the “Adjusted LIBO Rate” plus 40 basis points or the greater of (a) the “Prime Rate” and (b) the sum of the “Federal Funds Rate” plus 50 basis points, as defined in the agreement. Annual fees on the undrawn commitments are 8 basis points. The agreement contains provisions for revised pricing in the event of a ratings change. For example, a ratings downgrade of HECO’s Senior Debt Rating (e.g., from BBB+/Baa1 to BBB/Baa2 by S&P and Moody’s, respectively) would result in a commitment fee increase of 2 basis points and an interest rate increase of 10 basis points on any drawn amounts. On the other hand, a ratings upgrade (e.g., from BBB+/Baa1 to A-/A3) would result in a commitment fee decrease of 1 basis point and an interest rate decrease of 10 basis points on any drawn amounts. The agreement does not contain clauses that would affect access to the lines by reason of a ratings downgrade, nor does it have broad “material adverse change” clauses. However, the agreement does contain customary conditions that must be met in order to draw on it, including compliance with several covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HECO, and restricting its ability as well as the ability of any of its subsidiaries to guarantee indebtedness of the subsidiaries if such additional debt would cause the subsidiary’s “Consolidated Subsidiary Funded Debt to Capitalization Ratio” to exceed 65% (Ratio of 48% for HELCO and 44% for MECO as of June 30, 2006)). In addition to customary defaults, HECO’s failure to maintain its financial ratios, as defined in its agreement, or meet other requirements will result in an event of default. For example, under the agreement, it is an event of default if HECO fails to maintain a “Consolidated Capitalization Ratio” (equity) of at least 35% (ratio of 52% as of June 30, 2006), if HECO fails to remain a wholly-owned subsidiary of HEI or if any event or condition occurs that results in any “Material Indebtedness” of HECO or any of its significant subsidiaries being subject to acceleration prior to its scheduled maturity.

HECO’s $175 million credit facility is maintained to support the issuance of commercial paper, but also may be drawn for capital expenditures and general corporate purposes. This facility replaced HECO’s six bilateral bank lines of credit totaling $175 million, which were terminated concurrently with the effectiveness of the new syndicated facility. HECO plans to file with the PUC in the third quarter of 2006 an application seeking approval to extend the termination date of its credit agreement from March 29, 2007 to March 31, 2011. As of July 31, 2006, the $175 million of credit facilities were undrawn.

Operating activities provided $93 million in net cash during the first six months of 2006. Investing activities during the same period used net cash of $81 million primarily for capital expenditures, net of contributions in aid of construction. Financing activities for the same period used net cash of $9 million, primarily due to the payment of $30 million in common and preferred dividends, partly offset by a $27 million net increase in short term borrowings. In order to strengthen HECO’s balance sheet and support its investment in its reliability program, HECO does not plan to pay any dividends to HEI in the second half of 2006.

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 in February 2005 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 May 2005, up to $160 million of Special Purpose Revenue Bonds (SPRBs) ($100 million for HECO, $40 million for HELCO and $20 million for MECO) were authorized by the Hawaii legislature for issuance, with PUC approval of the projects to be financed, through June 30, 2010 to finance the electric utilities’ capital improvement projects. As of July 31, 2006, no SPRBs had been issued under this authorization.

In December 2005, an application was filed with the PUC requesting approval to issue up to a total of $165 million in taxable unsecured notes for HECO, MECO and HELCO (up to $100 million for HECO, up to $50 million for HELCO and up to $15 million for MECO). On January 20, 2006, a Registration Statement on Form S-3 was filed with the SEC covering $100 million, $50 million and $15 million aggregate principal amount, respectively, of long-term, unsecured taxable notes to be issued by HECO, HELCO and MECO, with the obligations of HELCO and

MECO to be fully and unconditionally guaranteed by HECO. It was anticipated that the proceeds from the sale of the notes would be used for capital expenditures and/or to repay short-term borrowings (including borrowings from affiliates) incurred for capital expenditures or to refinance short-term borrowings used for capital expenditures. However, the electric utilities are currently considering amending the PUC application in order to issue SPRBs instead of issuing the taxable unsecured notes.

BANK

RESULTS OF OPERATIONS


	Three months ended June 30				% change		Primary reason(s) for significant change
(in thousands)	2006		2005		% change		Primary reason(s) for significant change
Revenues	$	102,556	$	91,946	12	%	Higher interest income (resulting from higher average balances and yields on loans and higher yields on investment and mortgage-related securities, partly offset by lower average investment and mortgage-related securities balances) and higher noninterest income

Operating income		26,159		22,202	18		Higher net interest and noninterest income, partly offset by higher noninterest expense

Net income		16,218		13,552	20		Higher operating income

	Six months ended June 30				% change		Primary reason(s) for significant change
(in thousands)	2006		2005		% change		Primary reason(s) for significant change
Revenues	$	202,560	$	189,170	7	%	Higher interest income (resulting from higher average balances and yields on loans and higher yields on investment and mortgage-related securities, partly offset by lower average investment and mortgage-related securities balances) and higher noninterest income

Operating income		53,174		51,155	4		Higher net interest and noninterest income and lower noninterest expense, partly offset by the reversal in first quarter 2005 of allowance for loan losses

Net income		33,045		31,313	6		Higher operating income

See “Economic conditions” in the “HEI Consolidated” section above.

Net interest margin

Earnings of ASB depend primarily on net interest income, which is the difference between interest earned on earning assets and interest paid on costing liabilities. As a result of a prolonged, flat or inverted yield curve environment, margin compression remains an issue for ASB.

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. As of June 30, 2006, ASB’s loan portfolio mix, net, consisted of 73% residential loans, 12% commercial loans, 8% commercial real estate loans and 7% consumer loans. As of December 31, 2005, ASB’s loan portfolio mix, net, consisted of 74% residential loans, 11% commercial loans, 8% commercial real estate 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. In the second quarter of 2006, commercial loans grew by 14% and commercial real estate grew by 7%. While the outlook for the Hawaii economy remains positive, management does not expect the growth rate in these portfolios to remain at these levels for the remainder of 2006. Scheduled paydowns of a few large commercial loans in the second half of 2006 may cause commercial loan and commercial real estate loan balances to remain flat. Originating mortgages has been more difficult with the Hawaii real estate market beginning to stabilize. While real estate prices remain high, the number of sales transactions has declined, impacting ASB’s mortgage origination levels. Management believes this trend in real estate sales volumes will continue.

Deposits continue to be the largest source of funds for ASB 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. As of June 30, 2006, ASB’s costing liabilities consisted of 73% deposits and 27% other borrowings. As of December 31, 2005, ASB’s costing liabilities consisted of 74% deposits and 26% other borrowings. The shift in mix was due to a net outflow of deposits during the second quarter and contributed to increased funding costs. The deposit liabilities balance as of June 30, 2006 was 1.4% lower than the balance as of March 31, 2006 and 0.2% lower than the balance as of December 31, 2005. Additionally, the shift in deposit mix from lower cost savings and checking accounts to higher cost time deposits also contributed to increased funding costs. ASB believes that with the continued Fed rate increases, the difference between rates on its deposit accounts and the rates on alternative investments became significant enough to cause more customers to move deposits in search of higher yields. Because of this, and ASB’s outlook for a prolonged flat or inverted yield curve environment, management has made tactical shifts in order to retain deposits, including more aggressive repricing of certain deposit accounts, increased promotions and accelerating product launches. While ASB tries to control its overall deposit costs by selectively repricing certain deposit accounts, rather than the entire deposit base, management expects that the move to more aggressive repricing of selected accounts will cause deposit costs to increase faster than they have in the past, which could negatively impact ASB’s future net interest margin.

Other factors primarily affecting ASB’s operating results include fee income, provision (or reversal of allowance) for loan losses, gains or losses on sales of securities available-for-sale and expenses from operations.

Although higher long-term interest rates could reduce the market value of available-for-sale investments and mortgage-related securities and reduce stockholder’s equity through a balance sheet charge to AOCI, this reduction in the market value of investments and mortgage-related securities would not result in a charge to net income in the absence of an “other-than-temporary” impairment in the value of the securities. As of June 30, 2006 and December 31, 2005, the unrealized losses, net of tax benefits, on available-for-sale investments and mortgage-related securities (including securities pledged for repurchase agreements) in AOCI was $62 million and $37 million, respectively, reflecting the impact of higher interest rates. See “Quantitative and qualitative disclosures about market risk” for the impact of higher interest rates on ASB’s net portfolio value (NPV) ratio.

The following table sets forth average balances, interest and dividend income, interest expense and weighted-average yields earned and rates paid, for all categories of earning assets and costing liabilities for the three and six months ended June 30, 2006 and 2005.


	Three months ended June 30							Six months ended June 30
($ in thousands)	2006		2005		Change			2006		2005		Change
Loans receivable
Average balances ¹	$	3,663,737	$	3,380,147	$	283,590		$	3,624,688	$	3,329,720	$	294,968
Interest income ²		57,323		50,657		6,666			112,476		99,170		13,306
Weighted-average yield (%)		6.26		5.99		0.27			6.22		5.96		0.26
Investments and mortgage-related securities
Average balances	$	2,583,133	$	2,784,907	$	(201,774	)	$	2,594,742	$	2,844,659	$	(249,917	)
Interest income		30,055		26,881		3,174			59,228		60,955		(1,727	)
Weighted-average yield (%)		4.65		3.86		0.79			4.57		4.29		0.28
Other investments ³
Average balances	$	165,071	$	188,191	$	(23,120	)	$	172,841	$	175,563	$	(2,722	)
Interest and dividend income		815		642		173			1,719		1,431		288
Weighted-average yield (%)		1.95		1.35		0.60			1.98		1.63		0.35
Total earning assets
Average balances	$	6,411,941	$	6,353,245	$	58,696		$	6,392,271	$	6,349,942	$	42,329
Interest and dividend income		88,193		78,180		10,013			173,423		161,556		11,867
Weighted-average yield (%)		5.50		4.92		0.58			5.43		5.09		0.34
Deposit liabilities
Average balances	$	4,562,344	$	4,441,024	$	121,320		$	4,556,555	$	4,381,144	$	175,411
Interest expense		17,001		12,460		4,541			32,394		24,477		7,917
Weighted-average rate (%)		1.49		1.13		0.36			1.43		1.13		0.30
Other borrowings
Average balances	$	1,646,164	$	1,701,908	$	(55,744	)	$	1,630,220	$	1,743,878	$	(113,658	)
Interest expense		18,308		16,893		1,415			35,470		34,641		829
Weighted-average rate (%)		4.45		3.97		0.48			4.38		3.99		0.39
Total costing liabilities
Average balances	$	6,208,508	$	6,142,932	$	65,576		$	6,186,775	$	6,125,022	$	61,753
Interest expense		35,309		29,353		5,956			67,864		59,118		8,746
Weighted-average rate (%)		2.28		1.91		0.37			2.21		1.94		0.27
Net average balance	$	203,433	$	210,313	$	(6,880	)	$	205,496	$	224,920	$	(19,424	)
Net interest income		52,884		48,827		4,057			105,559		102,438		3,121
Interest rate spread (%)		3.22		3.01		0.21			3.22		3.15		0.07
Net interest margin (%)		3.30		3.07		0.23			3.30		3.21		0.09

¹	Includes nonaccrual loans.

²	Includes interest accrued prior to suspension of interest accrual on nonaccrual loans and loan fees of $1.4 million and $1.7 million for the three months ended June 30, 2006 and 2005, respectively, and $2.8 million and $3.3 million for the six months ended June 30, 2006 and 2005, respectively.

³	Includes federal funds sold, interest-bearing deposits and stock in the FHLB of Seattle. The stock in the FHLB of Seattle has not paid dividends since the first quarter of 2005.

Results – three months ended June 30, 2006

Net interest income for the three months ended June 30, 2006 increased by $4.1 million, or 8%, when compared to the same period in 2005. ASB continued to grow its loan portfolio, deposits and net interest margin, however, margin compression remains an issue due to the prolonged, flat or inverted yield curve environment. Increasing short-term rates continue to put upward pressure on deposit costs. Net interest margin increased from 3.07% in the second quarter of 2005 to 3.30% in the second quarter of 2006 as growth in the loan portfolio as well as higher yields on loans, investments and mortgage-related securities were partially offset by lower investment and mortgage-related securities balances and higher funding costs. The increase in the average loan portfolio balance was partly due to the continued strength in the Hawaii economy and real estate market and growth in the commercial loan portfolio as a result of the bank’s strategy to transform from a thrift to a community bank. The decrease in the average investment and mortgage-related securities portfolio was due to the reinvestment of proceeds from the repayment or sale of investment and mortgage-related securities into loans. The increase in yields on the investment and mortgage-related securities portfolio was due to a downward adjustment to the amortized cost and yield of the mortgage-related securities in the second quarter of 2005 as a result of changing prepayment expectations. The average deposit balance was $121 million higher in the second quarter of 2006 than in the second quarter of 2005.

Results – six months ended June 30, 2006

Net interest income before reversal of allowance for loan losses for the six months ended June 30, 2006 increased by $3.1 million, or 3%, when compared to the same period in 2005. ASB continued to grow its loan portfolio, deposits and net interest margin, however, margin compression remains an issue due to the prolonged, flat or inverted yield curve environment. Increasing short-term rates continue to put upward pressure on deposit costs. Net interest margin increased from 3.21% in the first six months of 2005 to 3.30% in the first six months of 2006 as growth in the loan portfolio and higher yields on loans and investment and mortgage-related securities were partially offset by lower investment and mortgage-related securities balances and higher funding costs. The increase in the average loan portfolio balance was partly due to the continued strength in the Hawaii economy and real estate market and growth in the commercial loan portfolio as result of the bank’s transformation from a thrift to a community bank. The decrease in the average investment and mortgage-related securities portfolio was due to the reinvestment of proceeds from the repayment or sale of investment and mortgage-related securities into loans. The increase in yields on the investment and mortgage-related securities portfolio was due to a downward adjustment to the amortized cost and yield of the mortgage-related securities in the first six months of 2005 as a result of changing prepayment expectations. The average deposit balance was $175 million higher in the first six months of 2006 compared to the first six months of 2005.

During the first six months of 2006, the need to provide for loan losses as a result of additional loan growth was fully offset by the release of reserves on existing loans due to strong asset quality. This compares to a reversal of allowance for loan losses of $3.1 million ($1.9 million, net of tax) for the first six months of 2005. As of June 30, 2006, ASB’s allowance for loan losses was 0.84% of average loans outstanding, compared to 0.90% as of December 31, 2005 and 0.92% as of June 30, 2005.


Six months ended June 30	2006			2005
(in thousands)
Allowance for loan losses, January 1	$	30,595		$	33,857
Reversal of allowance for loan losses		—			(3,100	)
Net recoveries (charge-offs)		(294	)		(119	)

Allowance for loan losses, June 30	$	30,301		$	30,638

Noninterest income for the first six months of 2006 increased by $1.5 million, or 6%, when compared to the first six months of 2005, primarily due to higher fee income on debit cards and merchant services.

Noninterest expense for the first six months of 2006 decreased by $0.5 million, or 1%, when compared to the first six months of 2005, primarily due to lower interest accruals on income taxes, partially offset by higher compensation and employee benefits expense.

FHLB of Seattle business and capital plan

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. 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. Subject to the impact of legislation being considered by Congress, member access to the FHLB of Seattle funding and liquidity is expected to continue unimpeded during implementation of the three-year plan.

As of June 30, 2006, ASB had an investment in FHLB of Seattle stock of $98 million. No dividends have been received by ASB from the FHLB of Seattle since first quarter of 2005.

FINANCIAL CONDITION

Liquidity and capital resources


(in millions)	June 30, 2006		December 31, 2005		% change
Total assets	$	6,867	$	6,835	—
Available-for-sale investment and mortgage-related securities		2,506		2,629	(5	)
Investment in FHLB of Seattle stock		98		98	—
Loans receivable, net		3,718		3,567	4
Deposit liabilities		4,547		4,557	—
Other borrowings		1,672		1,622	3

As of June 30, 2006, ASB was the third largest financial institution in Hawaii based on assets of $6.9 billion and deposits of $4.5 billion.

ASB’s S&P long-term/short-term counterparty credit ratings are BBB-/A-3. In April 2006, S&P affirmed its counterparty credit ratings on ASB and revised its outlook from stable to positive, acknowledging the promising potential of ASB’s community banking strategy, its still modest credit risk profile, and its solid capital base. These ratings are not recommendations to buy, sell or hold any securities; such ratings may be subject to revision or withdrawal at any time by S&P; and each rating should be evaluated independently of any other rating.

As of June 30, 2006, ASB’s unused FHLB borrowing capacity was approximately $1.6 billion. As of June 30, 2006, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.2 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 months of 2006, net cash provided by ASB’s operating activities was $78 million. Net cash used during the same period by ASB’s investing activities was $86 million, primarily due to purchases of investment securities of $175 million and a net increase in loans receivable of $159 million, partly offset by repayments of mortgage-related securities of $254 million. Net cash provided by financing activities during this period was $21 million primarily due to net increases of $49 million in other borrowings, partly offset by a net decrease of $11 million in deposit liabilities and the payment of $19 million in common stock dividends. In the second half of 2006, ASB plans to dividend all or substantially all of its second and third quarter net income to HEI, subject to receiving OTS non-objection letters and maintaining an adequate capital level.

As of June 30, 2006, ASB was well-capitalized (ratio requirements noted in parentheses) with a leverage ratio of 7.6% (5.0%), a Tier-1 risk-based capital ratio of 14.4% (6.0%) and a total risk-based capital ratio of 15.2% (10.0%).

CERTAIN FACTORS THAT MAY AFFECT FUTURE RESULTS AND FINANCIAL CONDITION

The Company’s results of operations and financial condition can be affected by numerous factors, many of which are beyond the Company’s control and could cause future results of operations to differ materially from historical results. For information about certain of these factors, see pages 80 to 86 of HEI’s and HECO’s 2005 Form 10-K.

Additional factors that may affect future results and financial condition are described under “Forward-Looking Statements” and under “Risk Factors” in this Quarterly Report and on pages 36 to 44 of HEI’s and HECO’s 2005 Form 10-K.

MATERIAL ESTIMATES AND CRITICAL ACCOUNTING POLICIES

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 86 to 89 of HEI’s and HECO’s 2005 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. For example, in determining that HECO is not the primary beneficiary of Kalaeloa under the provisions of FIN 46R (see Note 2 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, which could potentially trigger a reconsideration of whether HECO is the primary beneficiary of Kalaeloa.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

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 and HECO’s 2005 Form 10-K.

ASB’s interest-rate risk sensitivity measures as of June 30, 2006 and December 31, 2005 constitute “forward-looking statements” and were as follows:


	June 30, 2006						December 31, 2005
	Change in NII		NPV ratio		NPV ratio sensitivity *		Change in NII		NPV ratio		NPV ratio sensitivity *
Change in interest rates (basis points)	Gradual change		Instantaneous change				Gradual change		Instantaneous change
+300	(2.3	)%	7.36	%	(367	)	(2.7	)%	8.12	%	(332	)
+200	(1.6	)	8.62		(241	)	(1.8	)	9.34		(210	)
+100	(0.8	)	9.88		(115	)	(0.9	)	10.49		(95	)
Base	—		11.03		—		—		11.44		—
-100	1.7		11.87		84		1.5		11.91		47
-200	1.7		12.03		100		1.0		11.62		18
-300	0.2		11.51		48			**		**		**

*	Change from base case in basis points.

**	Not performed as of December 31, 2005.

There was little change in the net interest income (NII) sensitivity profile as of June 30, 2006 when compared to the NII sensitivity profile as of December 31, 2005.

ASB’s base NPV ratio as of June 30, 2006 was lower than on December 31, 2005, primarily as a result of the increase in the overall level of interest rates that took place during the first six months of 2006.

ASB’s NPV ratio sensitivity measures as of June 30, 2006 were higher when compared to the measures as of December 31, 2005, primarily a result of the higher level of interest rates.

The computation of the prospective effects of hypothetical interest rate changes on NII sensitivity, the NPV ratio, and NPV ratio sensitivity is based on numerous assumptions, including relative levels of market interest rates, estimates of loan prepayments, balance changes and pricing strategies, and should not be relied upon as indicative

of actual results. (See page 91 of HEI’s and HECO’s 2005 Form 10-K for a more detailed description of key modeling assumptions used in the NII sensitivity analysis.) 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. These analyses are for analytical purposes only and do not represent management’s views of future market movements, the level of future earnings, or the timing of any changes in earnings within the twelve month analysis horizon. Furthermore, NII sensitivity analysis measures the change in ASB’s twelve-month, pre-tax NII in alternate interest rate scenarios, and is intended to help management identify potential exposures in ASB’s current balance sheet and formulate appropriate strategies for managing interest rate risk. The simulation does not contemplate any actions that ASB management might undertake in response to changes in interest rates. Further, the changes in NII vary in the twelve-month simulation period and are not necessarily evenly distributed over the period. The actual impact of changes in interest rates on NII will depend on the magnitude and speed with which rates change, actual changes in ASB’s balance sheet, and management’s responses to the changes in interest rates.

Item 4.

Controls and Procedures

HEI:

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Constance H. Lau, HEI Chief Executive Officer, and Eric K. Yeaman, HEI Chief Financial Officer, have evaluated the disclosure controls and procedures of HEI as of June 30, 2006. Based on their evaluations, as of June 30, 2006, 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) were effective in ensuring that information required to be disclosed by HEI in reports HEI files or submits under the Securities Exchange Act of 1934:

(1)

is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and

(2)

is accumulated and communicated to HEI management, including HEI’s principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Internal Control Over Financial Reporting

During the second quarter of 2006, there has been no change in internal control over financial reporting identified in connection with management’s evaluation of the effectiveness of the Company’s internal control over financial reporting as of June 30, 2006 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

HECO:

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

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 30, 2006. Based on their evaluations, as of June 30, 2006, 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) were effective in ensuring that information required to be disclosed by HECO in reports HECO files or submits under the Securities Exchange Act of 1934:

(1)

is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and

(2)

is accumulated and communicated to HECO management, including HECO’s principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Internal Control Over Financial Reporting

During the second quarter of 2006, there has been no change in internal control over financial reporting identified in connection with management’s evaluation of the effectiveness of HECO and its subsidiaries’ internal control over financial reporting as of June 30, 2006 that has materially affected, or is reasonably likely to materially affect, HECO and its subsidiaries’ internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1.

Legal Proceedings

There were no significant developments in pending legal proceedings during the first six months of 2006 except as set forth in HECO’s “Notes to Consolidated Financial Statements.” 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.

Item 1A.

Risk Factors

For information about Risk Factors, see pages 36 to 44 of HEI’s and HECO’s 2005 Form 10-K, and “Forward-Looking Statements,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Quantitative and Qualitative Disclosures about Market Risk,” HEI’s Consolidated Financial Statements and HECO’s Consolidated Financial Statements herein.

Following are updates to the captioned risk factors included in HEI’s and HECO’s 2005 Form 10-K:

Holding Company and Company-Wide Risks

The Company could be subject to the risk of uninsured losses in excess of its accruals for litigation matters.

HEI and its subsidiaries are involved in routine litigation in the ordinary course of their businesses, most of which is covered by insurance (subject to policy limits and deductibles). However, other litigation may arise that is not routine or involves claims that may not be covered by insurance. Because of the uncertainties associated with litigation, there is a risk that litigation against HEI and its subsidiaries, even if vigorously defended, could result in costs of defense and judgment or settlement amounts not covered by insurance and in excess of reserves established in HEI’s consolidated financial statements.

HEI and HECO and their subsidiaries may incur higher retirement benefits expenses and could be required to recognize substantial liabilities for retirement benefits.

Retirement benefits expenses and cash funding requirements could increase in future years depending on numerous factors, including the performance of the U.S. equity markets, trends in interest rates and health care costs, new legislation relating to pension reform and changes in accounting principles. Retirement benefits expenses based on net periodic pension and other postretirement benefit costs have been an allowable expense for rate-making, and higher retirement benefits expenses, along with other factors, may affect each electric utilities’ need to request a rate increase.

Depending on investment results at each year end from the assets held in trust to satisfy retirement benefit plan obligations and the status of interest rates, the Company, like many sponsors of defined benefit pension plans, could be required in future years to recognize an additional minimum liability as currently prescribed by Statement of Accounting Standards (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 on the measurement date. The electric utilities’ recognition of the liability would also require the removal of the prepaid pension asset ($106 million as of December 31, 2005) from their consolidated balance sheet and from their rate bases and the sum of these amounts (net of taxes) would be recorded as a reduction to stockholders’ equity through a non-cash charge to accumulated other comprehensive income (AOCI). The amount of additional minimum liability and charge to AOCI, if any, that might be recorded could be material and will depend upon a number of factors, including the year-end discount rate assumption, asset returns experienced during the year, any changes to actuarial assumptions or plan provisions, and contributions made by the Company to the plans during the year.

By application filed on December 8, 2005 (AOCI Docket), the electric utilities have requested the PUC to permit them to record, as a regulatory asset pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” and include in rate base, any amount that would otherwise be charged to AOCI as a result of recording a minimum pension liability, but no assurance can be given concerning how or when the PUC will act on this request.

In March 2006, the FASB issued an exposure draft, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R),” which is subject to change, and which, if adopted in its current form, could have a material impact on HEI’s and HECO’s consolidated stockholders’ equity. This proposed SFAS would require the Company to (1) recognize the overfunded or underfunded status of its defined benefit pension and other postretirement plans (based on the difference between the fair value of the plan assets and the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans) in its balance sheet, (2) recognize as a component of AOCI, net of tax, the actuarial gains and losses and the prior service costs and credits that arise during the period but are not recognized as components of net periodic benefit cost, (3) recognize as an adjustment to the opening balance of retained earnings, net of tax, any remaining transition obligation, and (4) disclose additional information in the notes to financial statements about certain effects on net periodic benefit cost in the upcoming fiscal year that arise from delayed recognition of the actuarial gains and losses and the prior service costs and credits. If adopted in its current form, the provisions of this proposed SFAS would be applied retrospectively for the year ending December 31, 2006.

If this FASB proposal is adopted, the electric utilities plan to update their application in the existing AOCI Docket to seek PUC approval to record as a regulatory asset and include in rate base the amount that would otherwise be charged to stockholders’ equity. If their request is granted, to the extent the electric utilities determine that it is probable that the additional liabilities will be recoverable through rates they charge, a regulatory asset would be recorded and there would be no material impact of adopting this proposed standard on HEI’s or HECO’s consolidated stockholders’ equity or net income.

If the PUC were not to grant regulatory asset treatment in the existing AOCI Docket or the AOCI Docket as updated if the proposed SFAS is adopted, there could be a materially negative impact (the amount of which is dependent on numerous factors, some of which are listed above) to HEI’s and HECO’s consolidated stockholders’ equity. Although there would not be an immediate impact on net income under the provisions of the existing or proposed retirement benefits standards due to the non-regulatory asset treatment, if HEI and HECO and their subsidiaries are required to record substantial charges to stockholders’ equity, the rates of return for the electric utilities could increase and could impact the rates the electric utilities are allowed to charge, which may ultimately result in reduced revenues and lower earnings. Further potential negative impacts include the fact that the consolidated financial ratios of HEI and HECO and their subsidiaries may deteriorate, which could result in security ratings downgrades and difficulty (or greater expense) in obtaining future financing.

Electric Utility Risks

Actions of the PUC are outside the control of the electric utility subsidiaries and could result in inadequate or untimely rate relief, in rate reductions or refunds or in unanticipated delays, expenses or writedowns in connection with the construction of new projects.

The rates the electric utilities are allowed to charge for their services and the timeliness of permitted rate increases, are among the most important items influencing the electric utilities’ financial condition, results of operations and liquidity. The PUC has broad discretion over the rates that the electric utilities charge their customers. HECO currently has a rate case pending before the PUC in which it is seeking rate increases largely to recover the costs of capital improvements since its last rate case, the purchase of additional firm capacity and energy from Kalaeloa, the cost of measures taken to address peak load increases until generation capacity can be added on Oahu and increased operation and maintenance (O&M) expenses. In addition, in May 2006 HELCO filed a request for a rate increase intended largely to recover the cost of improvements to its transmission and distribution lines and the two generating units at its Keahole generating plant (CT-4 and CT-5) that became available for commercial operation since its last rate case in 2000. The trend of increased O&M expenses (including increased retirement benefits expenses), which management expects will continue, increased capital expenditures, or other factors could result in the electric utilities seeking rate relief more often than in the past. Any adverse decision by the PUC concerning the level or method of determining electric utility rates, the returns on equity or rate base found to be reasonable, the potential consequences of exceeding or not meeting such returns, or any prolonged delay in rendering a decision in a rate or other proceeding, could have a material adverse effect on HECO’s consolidated financial condition, results of operations and liquidity.

The electric utilities could be required to refund to their customers, with interest, revenues received under interim rate orders if and to the extent they exceed the amounts allowed in final rate orders. At the end of September 2005, HECO received and implemented an interim general rate increase of $53.3 million in annual base revenues granted by the PUC in HECO’s current rate case. As of June 30, 2006, the electric utilities had recognized an aggregate of $57 million of revenues with respect to this interim general rate increase and other interim orders regarding certain integrated resource planning costs.

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

On June 19, 2006, the PUC issued an order in HECO’s pending rate case, indicating that the record in the pending case has not been developed for the purpose of addressing the factors in Act 162, signed into law by the Governor of Hawaii on June 2, 2006. See “Energy cost adjustment clauses” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.” Management cannot predict whether the PUC will accept the disposition of the Act 162 issue proposed in the stipulation between HECO and the Consumer Advocate or, if not, the procedural steps or procedural schedule that will be adopted to address the issues that are raised by Act 162, the ultimate outcome of these issues, the effect of these issues on the operation of the ECAC as it relates to the electric utilities or the timing of the PUC’s issuance of a final D&O in HECO’s pending rate case.

Many public utility projects require PUC approval and various permits (e.g., environmental and land use permits) from other governmental agencies. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits, or any adverse decision or policy made or adopted, or any prolonged delay in rendering a decision, by an agency with respect to such approvals and permits, can result in significantly increased project costs or even cancellation of projects. For example, two major capital improvement projects — HECO’s East Oahu Transmission Project and the expansion of HELCO’s Keahole generating plant — have encountered substantial opposition and consequent delay and increased cost. In the event a project does not proceed, or if the PUC disallows cost recovery for all or part of the project, project costs may need to be written off in amounts that could result in significant reductions in HECO’s consolidated net income.

The electric utilities may be adversely affected by new legislation.

For updates of the 2006 Hawaii State Legislature energy measures that were signed into law by the Governor of Hawaii and net energy metering, see “Legislation and regulation” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

(a) For the six months ended June 30, 2006, HEI issued an aggregate of 15,400 shares of unregistered common stock pursuant to the HEI 1990 Nonemployee Director Stock Plan, as amended and restated effective May 2, 2006 (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 shares 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” 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.

(b) Purchases of HEI common shares were made as follows:

ISSUER PURCHASES OF EQUITY SECURITIES


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, 2006	39,519	$	26.40	—	NA
May 1 to 31, 2006	86,716		26.52	—	NA
June 1 to 30, 2006	250,271		27.53	—	NA

	376,506	$	27.18	—	NA

NA Not applicable.

*	Trades (total number of shares purchased) are reflected in the month in which the order is placed.

The purchases were made to satisfy the requirements of the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP) and Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) for shares purchased for cash or by the reinvestment of dividends by participants under those plans and none of the purchases were made under publicly announced repurchase plans or programs. Average prices per share are calculated exclusive of any commissions payable to the brokers making the purchases for the DRIP and HEIRSP. Of the shares listed in column (a), all of the 39,519 shares, 79,316 of the 86,716 shares and 217,971 of the 250,271 shares were purchased for the DRIP and the remainder were purchased for the HEIRSP. All purchases were made through a broker on the open market.

Item 4.

Submission of matters to a vote of security holders

HEI: The Annual Meeting of Shareholders of HEI was held on May 2, 2006. Proxies for the meeting were solicited pursuant to Regulation 14A under the Securities Exchange Act of 1934. As of February 23, 2006, the record date for the Annual Meeting, there were 81,051,976 shares of common stock issued and outstanding and entitled to vote. There was no solicitation in opposition to the Class I management nominees to the Board of Directors with terms ending at the 2009 Annual Meeting as listed in the proxy statement for the meeting and such nominees were elected to the Board of Directors. Shareholders also elected KPMG LLP as HEI’s independent registered public accounting firm for 2006, amended Articles Fourth (to increase the number of authorized shares of common stock) and Sixth (to modify the manner of selecting HEI’s auditor) of HEI’s Restated Articles of Incorporation, and approved the 1990 Nonemployee Director Stock Plan, as amended and restated (see HEI Exhibit 10). The amended Articles Fourth and Sixth of HEI’s Restated Articles of Incorporation were filed as Exhibits 3(i).4 and 3(i).5 to HEI’s 10-Q for the quarterly period ended March 31, 2006.

The voting results were as follows:


	Shares of Common Stock
	For	Withheld	Against	Abstain	Broker nonvotes
Election of Class I Directors
Shirley J. Daniel	73,034,052	1,590,535	—	—	—
Constance H. Lau	73,017,131	1,607,456	—	—	—
A. Maurice Myers	72,731,570	1,893,017	—	—	—
James K. Scott	72,514,502	2,110,085	—	—	—
Election of KPMG LLP as independent registered public accounting firm	73,026,315	—	1,011,052	587,220	—
Restated Articles of Incorporation
Article Fourth	68,955,601	—	4,536,886	1,132,100	—
Article Sixth	70,994,593	—	2,218,119	1,411,875	—
1990 Nonemployee Director Stock Plan, as amended and restated	42,473,060	—	4,821,305	2,623,747	27,424,473

Class II Directors—Diane J. Plotts, Kelvin H. Taketa, Jeffrey N. Watanabe and Thomas B. Fargo—continue in office with terms ending at the 2007 Annual Meeting. Class III Directors—Don E. Carroll, Victor Hao Li, Bill D. Mills and Barry K. Taniguchi—continue in office with terms ending at the 2008 Annual Meeting.

HECO: Effective May 2, 2006, HEI, HECO’s sole common shareholder, elected by written consent in lieu of an annual meeting (1) Constance H. Lau as Chairman of the HECO Board of Directors (replacing incumbent director Robert F. Clarke, who announced his retirement from HEI and whose service as a HECO director ended at HEI’s 2006 Annual Meeting of Shareholders), (2) other incumbent HECO directors and (3) KPMG LLP as independent registered public accounting firm of HECO for 2006. In July 2006, as part of an overall Board restructure, A. Maurice Myers, Diane J. Plotts, Crystal K. Rose and Jeffrey N. Watanabe resigned from the HECO Board and David C. Cole and Bert A. Kobayashi, Jr. were elected to the HECO Board. Effective July 24, 2006, the members of the HECO Board are Thomas B. Fargo, Timothy E. Johns, Constance H. Lau (Chairman), T. Michael May, David M. Nakada, James K. Scott, Anne M. Takabuki, Kelvin H. Taketa and Barry K. Taniguchi (incumbent directors), and David C. Cole and Bert A. Kobayashi, Jr. (new directors).

Item 5.

Other Information

A.	Ratio of earnings to fixed charges.


	Six months ended June 30		Years ended December 31
	2006	2005	2005	2004	2003	2002	2001
HEI and Subsidiaries
Excluding interest on ASB deposits	2.21	2.07	2.31	2.32	2.11	2.03	1.82
Including interest on ASB deposits	1.85	1.81	1.98	2.00	1.84	1.72	1.52
HECO and Subsidiaries	3.16	3.00	3.23	3.49	3.36	3.71	3.51

See HEI Exhibit 12.1 and HECO Exhibit 12.2.

B.	News release.

On August 1, 2006, HEI issued a news release, “Hawaiian Electric Industries, Inc. Reports Second Quarter 2006 Earnings.” See HEI Exhibit 99.

C.	Public Utilities Commission of the State of Hawaii.

Carlito P. Caliboso (an attorney previously in private practice) continues to serve as Chairman of the PUC (term expiring June 30, 2010). Also serving as commissioners are Wayne H. Kimura (whose term expires June 30, 2008 and who previously served as State Comptroller with the State Department of Accounting and General Services) and John E. Cole (whose term expires June 30, 2012 and who previously served as the Executive Director of the Division of Consumer Advocacy, and prior to holding that position as a member of the Governor of the State of Hawaii’s Policy Team, which serves as advisor to the Governor on state-wide policy matters).

A new Executive Director of the Division of Consumer Advocacy has not yet been appointed.

Commissioner Kimura announced plans to resign effective August 1, 2006. A replacement has not yet been announced.

D.	Renewable Hawaii, Inc.

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 for a small-scale landfill gas-to-energy project on Oahu. RHI has also signed a Framework Agreement for evaluation of three wind projects and two pumped storage hydroelectric projects and two Project Agreements providing the option to invest in wind projects. 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.

Item 6.

Exhibits


HEI Exhibit 10		HEI 1990 Nonemployee Director Stock Plan, As Amended and Restated, effective May 2, 2006

HEI Exhibit 12.1		Hawaiian Electric Industries, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, six months ended June 30, 2006 and 2005 and years ended December 31, 2005, 2004, 2003, 2002 and 2001

HEI Exhibit 31.1		Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Constance H. Lau (HEI Chief Executive Officer)

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

HEI Exhibit 32.1		Written Statement of Constance H. Lau (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		News release, dated August 1, 2006, “Hawaiian Electric Industries, Inc. Reports Second Quarter 2006 Earnings”

HECO Exhibit 12.2		Hawaiian Electric Company, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, six months ended June 30, 2006 and 2005 and years ended December 31, 2005, 2004, 2003, 2002 and 2001

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

HECO Exhibit 31.4		Certification Pursuant to Rule 13a-14 promulgated under 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

SIGNATURES

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


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

By	/s/ Constance H. Lau	By	/s/ T. Michael May
	Constance H. Lau		T. Michael May
	President and Chief Executive Officer (Principal Executive Officer of HEI)		President and Chief Executive Officer (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)

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

Date: August 1, 2006		Date: August 1, 2006