Edgar Filing: HAWAIIAN ELECTRIC CO INC

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended September 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 October 27, 2006
Hawaiian Electric Industries, Inc. (Without Par Value)				81,349,570 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 September 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) - September 30, 2006 and December 31, 2005	1

	Consolidated Statements of Income (unaudited) - three and nine months ended September 30, 2006 and 2005	2

	Consolidated Statements of Changes in Stockholders’ Equity (unaudited) - nine months ended September 30, 2006 and 2005	3

	Consolidated Statements of Cash Flows (unaudited) - nine months ended September 30, 2006 and 2005	4

	Notes to Consolidated Financial Statements (unaudited)	5

	Hawaiian Electric Company, Inc. and Subsidiaries

	Consolidated Balance Sheets (unaudited) - September 30, 2006 and December 31, 2005	17

	Consolidated Statements of Income (unaudited) - three and nine months ended September 30, 2006 and 2005	18

	Consolidated Statements of Retained Earnings (unaudited) - three and nine months ended September 30, 2006 and 2005	18

	Consolidated Statements of Cash Flows (unaudited) - nine months ended September 30, 2006 and 2005	19

	Notes to Consolidated Financial Statements (unaudited)	20

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38

	HEI Consolidated	38

	Electric Utilities	45

	Bank	61

	Certain Factors that May Affect Future Results and Financial Condition	66

	Material Estimates and Critical Accounting Policies	66

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	67

Item 4.	Controls and Procedures	68

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	69

Item 1A.	Risk Factors	69

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	73

Item 5.	Other Information	73

Item 6.	Exhibits	74

Signatures		75

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended September 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		U.S. generally accepted accounting principles

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

IRS		Internal Revenue Service

KWH		Kilowatthour

MD&A		Management’s discussion and analysis of financial condition and results of operation

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

PURPA		Public Utility Regulatory Policies Act of 1978

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, such as hurricanes, earthquakes and tsunamis;

•

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, North Korea’s and 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;

•

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 continued to be strained;

•

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, renewable portfolio standards (RPS), 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 Statement of Financial Accounting Standards (SFAS) No. 158 regarding employers’ accounting for defined benefit pension and other postretirement plans), continued regulatory accounting under 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 cost or 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)	September 30, 2006			December 31, 2005
Assets
Cash and equivalents	$	146,917		$	151,513
Federal funds sold		44,667			57,434
Accounts receivable and unbilled revenues, net		271,203			249,473
Available-for-sale investment and mortgage-related securities		2,357,012			2,629,351
Investment in stock of Federal Home Loan Bank of Seattle, at cost		97,764			97,764
Loans receivable, net		3,763,823			3,566,834
Property, plant and equipment, net of accumulated depreciation of $1,624,126 and $1,538,836		2,605,392			2,542,776
Regulatory assets		110,335			110,718
Other		424,712			456,134
Goodwill and other intangibles, net		88,011			89,580

	$	9,909,836		$	9,951,577

Liabilities and stockholders’ equity
Liabilities
Accounts payable	$	178,132		$	183,336
Deposit liabilities		4,540,124			4,557,419
Short-term borrowings—other than bank		194,211			141,758
Other bank borrowings		1,511,956			1,622,294
Long-term debt, net—other than bank		1,133,137			1,142,993
Deferred income taxes		197,800			207,997
Regulatory liabilities		235,480			219,204
Contributions in aid of construction		265,739			256,263
Other		380,957			369,390

		8,637,536			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: 81,349,570 shares and 80,983,326 shares		1,025,312			1,018,966
Retained earnings		251,768			235,394
Accumulated other comprehensive loss, net of tax benefits		(39,073	)		(37,730	)

		1,238,007			1,216,630

	$	9,909,836		$	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 September 30						Nine months ended September 30
	2006			2005			2006			2005
Revenues
Electric utility	$	569,838		$	491,339		$	1,548,861		$	1,295,844
Bank		103,338			97,431			305,898			286,601
Other		718			7,145			(934	)		8,360

		673,894			595,915			1,853,825			1,590,805

Expenses
Electric utility		521,187			443,806			1,414,784			1,174,058
Bank		82,760			71,493			232,146			209,508
Other		3,591			3,377			10,659			11,880

		607,538			518,676			1,657,589			1,395,446

Operating income (loss)
Electric utility		48,651			47,533			134,077			121,786
Bank		20,578			25,938			73,752			77,093
Other		(2,873	)		3,768			(11,593	)		(3,520	)

		66,356			77,239			196,236			195,359

Interest expense—other than bank		(18,275	)		(18,990	)		(56,526	)		(56,955	)
Allowance for borrowed funds used during construction		838			558			2,259			1,460
Preferred stock dividends of subsidiaries		(471	)		(471	)		(1,417	)		(1,421	)
Allowance for equity funds used during construction		1,838			1,406			4,974			3,675

Income from continuing operations before income taxes		50,286			59,742			145,526			142,118
Income taxes		17,963			22,252			53,642			52,198

Income from continuing operations		32,323			37,490			91,884			89,920
Discontinued operations-loss on disposal, net of income taxes		—			—			—			(755	)

Net income	$	32,323		$	37,490		$	91,884		$	89,165

Basic earnings (loss) per common share
Continuing operations	$	0.40		$	0.46		$	1.13		$	1.11
Discontinued operations		—			—			—			(0.01	)

	$	0.40		$	0.46		$	1.13		$	1.10

Diluted earnings (loss) per common share
Continuing operations	$	0.40		$	0.46		$	1.13		$	1.11
Discontinued operations		—			—			—			(0.01	)

	$	0.40		$	0.46		$	1.13		$	1.10

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

Weighted-average number of common shares outstanding		81,213			80,903			81,099			80,795
Dilutive effect of stock options and dividend equivalents		343			444			284			389

Adjusted weighted-average shares		81,556			81,347			81,383			81,184

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

Including interest on ASB deposits								1.85			1.93

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	—		—		91,884			—			91,884
Net unrealized losses on securities:
Net unrealized losses arising during the period, net of income tax benefits of $164	—		—		—			(250	)		(250	)
Less: reclassification adjustment for net realized gains included in net income, net of income taxes of $690								(1,045	)		(1,045	)
Minimum pension liability adjustment, net of income tax benefits of $30	—		—		—			(48	)		(48	)

Comprehensive income (loss)	—		—		91,884			(1,343	)		90,541

Issuance of common stock, net	367		6,346		—			—			6,346
Common stock dividends ($0.93 per share)	—		—		(75,510	)		—			(75,510	)

Balance, September 30, 2006	81,350	$	1,025,312	$	251,768		$	(39,073	)	$	1,238,007

Balance, December 31, 2004	80,687	$	1,010,090	$	208,998		$	(8,143	)	$	1,210,945
Comprehensive income:
Net income	—		—		89,165			—			89,165
Net unrealized losses on securities:
Net unrealized losses on securities arising during the period, net of income tax benefits of $15,459	—		—		—			(19,532	)		(19,532	)
Less: reclassification adjustment for net realized gains included in net income, net of income taxes of $70	—		—		—			(106	)		(106	)

Comprehensive income (loss)	—		—		89,165			(19,638	)		69,527

Issuance of common stock, net	269		8,080		—			—			8,080
Common stock dividends ($0.93 per share)	—		—		(75,194	)		—			(75,194	)

Balance, September 30, 2005	80,956	$	1,018,170	$	222,969		$	(27,781	)	$	1,213,358

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

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)


Nine months ended September 30	2006			2005
(in thousands)
Cash flows from operating activities
Net income	$	91,884		$	89,920
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment		105,862			100,391
Other amortization		7,790			7,565
Reversal of allowance for loan losses		—			(3,100	)
Deferred income taxes		(8,961	)		19,843
Allowance for equity funds used during construction		(4,974	)		(3,675	)
Excess tax benefits from share-based payment arrangements		(697	)		—
Changes in assets and liabilities, net of effects from the disposal of businesses
Increase in accounts receivable and unbilled revenues, net		(21,730	)		(30,600	)
Decrease (increase) in federal tax deposit		30,000			(30,000	)
Increase (decrease) in accounts payable		(5,204	)		28,527
Changes in other assets and liabilities		9,412			(22,492	)

Net cash provided by operating activities		203,382			156,379

Cash flows from investing activities
Available-for-sale investment and mortgage-related securities purchased		(175,000	)		(411,811	)
Principal repayments on available-for-sale mortgage-related securities		381,960			555,640
Proceeds from sale of available-for-sale mortgage-related securities		61,131			28,039
Net increase in loans held for investment		(196,795	)		(243,452	)
Capital expenditures		(146,982	)		(146,696	)
Contributions in aid of construction		13,227			10,274
Other		2,043			1,197

Net cash used in investing activities		(60,416	)		(206,809	)

Cash flows from financing activities
Net increase (decrease) in deposit liabilities		(17,295	)		255,665
Net increase in short-term borrowings with original maturities of three months or less		53,153			44,031
Proceeds from short-term borrowings with original maturities of greater than three months		44,890			—
Repayment of short-term borrowings with original maturities of greater than three months		(45,590	)		—
Net increase in retail repurchase agreements		45,577			17,717
Proceeds from other bank borrowings		1,050,907			847,056
Repayments of other bank borrowings		(1,206,828	)		(975,981	)
Proceeds from issuance of long-term debt		100,000			58,525
Repayment of long-term debt		(110,000	)		(53,000	)
Excess tax benefits from share-based payment arrangements		697			—
Net proceeds from issuance of common stock		3,392			3,232
Common stock dividends		(75,469	)		(75,153	)
Other		(10,953	)		(10,354	)

Net cash provided by (used in) financing activities		(167,519	)		111,738

Cash flows from discontinued operations-net cash provided by (used in) operating activities (revised see Note 8)		7,190			(2,462	)

Net increase (decrease) in cash and equivalents and federal funds sold		(17,363	)		58,846
Cash and equivalents and federal funds sold, beginning of period		208,947			173,629

Cash and equivalents and federal funds sold, end of period	$	191,584		$	232,475

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 U.S. generally accepted accounting principles (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 included in HEI’s Quarterly Reports on SEC Form 10-Q for the quarters ended March 31, 2006 and June 30, 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 September 30, 2006 and December 31, 2005, the results of its operations for the three and nine months ended September 30, 2006 and 2005 and its cash flows for the nine months ended September 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 September 30, 2006
Revenues from external customers	$	569,768	$	103,338	$	788		$	673,894
Intersegment revenues (eliminations)		70		—		(70	)		—

Revenues		569,838		103,338		718			673,894

Profit (loss)*		38,202		20,578		(8,494	)		50,286
Income taxes (benefit)		14,536		7,108		(3,681	)		17,963

Income (loss) from continuing operations		23,666		13,470		(4,813	)		32,323

Nine months ended September 30, 2006
Revenues from external customers		1,548,651		305,898		(724	)		1,853,825
Intersegment revenues (eliminations)		210		—		(210	)		—

Revenues		1,548,861		305,898		(934	)		1,853,825

Profit (loss)*		100,408		73,752		(28,634	)		145,526
Income taxes (benefit)		38,468		27,237		(12,063	)		53,642

Income (loss) from continuing operations		61,940		46,515		(16,571	)		91,884

Assets (at September 30, 2006, including net assets of discontinued operations)		3,165,272		6,714,395		30,169			9,909,836

Three months ended September 30, 2005
Revenues from external customers	$	491,263	$	97,431	$	7,221		$	595,915
Intersegment revenues (eliminations)		76		—		(76	)		—

Revenues		491,339		97,431		7,145			595,915

Profit (loss)*		36,315		25,938		(2,511	)		59,742
Income taxes (benefit)		13,728		10,027		(1,503	)		22,252

Income (loss) from continuing operations		22,587		15,911		(1,008	)		37,490

Nine months ended September 30, 2005
Revenues from external customers		1,295,721		286,601		8,483			1,590,805
Intersegment revenues (eliminations)		123		—		(123	)		—

Revenues		1,295,844		286,601		8,360			1,590,805

Profit (loss)*		88,288		77,044		(23,214	)		142,118
Income taxes (benefit)		33,672		29,820		(11,294	)		52,198

Income (loss) from continuing operations		54,616		47,224		(11,920	)		89,920

Assets (at September 30, 2005, including net assets of discontinued operations)		2,998,745		6,901,465		75,308			9,975,518

*	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 17 through 37.

(4) Bank subsidiary

Selected financial information

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

Consolidated Balance Sheet Data (unaudited)


(in thousands)	September 30, 2006			December 31, 2005
Assets
Cash and equivalents	$	140,090		$	150,130
Federal funds sold		44,667			57,434
Available-for-sale investment and mortgage-related securities		2,357,012			2,629,351
Investment in stock of Federal Home Loan Bank of Seattle, at cost		97,764			97,764
Loans receivable, net		3,763,823			3,566,834
Other		223,151			244,443
Goodwill and other intangibles, net		87,888			89,379

	$	6,714,395		$	6,835,335

Liabilities and stockholder’s equity
Deposit liabilities–noninterest-bearing	$	645,608		$	624,497
Deposit liabilities–interest-bearing		3,894,516			3,932,922
Other borrowings		1,511,956			1,622,294
Other		93,237			98,189

		6,145,317			6,277,902

Common stock		322,809			321,538
Retained earnings		284,249			272,545
Accumulated other comprehensive loss, net of tax benefits		(37,980	)		(36,650	)

		569,078			557,433

	$	6,714,395		$	6,835,335

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

Consolidated Statements of Income Data (unaudited)


	Three months ended September 30				Nine months ended September 30
(in thousands)	2006		2005		2006		2005
Interest and dividend income
Interest and fees on loans	$	59,417	$	52,649	$	171,893	$	151,819
Interest and dividends on investment and mortgage-related securities		28,368		30,889		89,315		93,275

		87,785		83,538		261,208		245,094

Interest expense
Interest on deposit liabilities		19,701		13,355		52,095		37,832
Interest on other borrowings		18,891		17,278		54,361		51,919

		38,592		30,633		106,456		89,751

Net interest income		49,193		52,905		154,752		155,343
Reversal of allowance for loan losses		—		—		—		(3,100	)

Net interest income after reversal of allowance for loan losses		49,193		52,905		154,752		158,443

Noninterest income
Fees from other financial services		6,548		6,512		19,730		18,708
Fee income on deposit liabilities		4,653		4,311		13,218		12,574
Fee income on other financial products		1,739		2,191		6,308		6,780
Gain on sale of securities		1,735		—		1,735		175
Other income		878		879		3,699		3,270

		15,553		13,893		44,690		41,507

Noninterest expense
Compensation and employee benefits		17,398		17,275		52,711		51,343
Occupancy		4,942		4,356		13,895		12,462
Equipment		3,768		3,413		10,900		10,114
Services		5,600		3,986		13,441		11,594
Data processing		2,534		2,491		7,541		8,039
Other expenses		9,926		9,339		27,202		29,305

		44,168		40,860		125,690		122,857

Income before minority interests and income taxes		20,578		25,938		73,752		77,093
Minority interests		—		—		—		45
Income taxes		7,108		10,027		27,237		29,820

Income before preferred stock dividends		13,470		15,911		46,515		47,228
Preferred stock dividends		—		—		—		4

Net income for common stock	$	13,470	$	15,911	$	46,515	$	47,224

Other borrowings consisted of securities sold under agreements to repurchase and advances from the Federal Home Loan Bank (FHLB) of Seattle of $739 million and $773 million, respectively, as of September 30, 2006 and $687 million and $935 million, respectively, as of December 31, 2005.

As of September 30, 2006, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.1 billion. As of September 30, 2006, ASB had commitments to sell nonresidential loans of $20.4 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 nine months of 2006, ASB paid $2 million and HECO paid $8 million in contributions to their respective retirement benefit plans, compared to $6 million and $8 million, respectively, in the first nine months of 2005. The Company’s current estimate of contributions to its 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 September 30												Nine months ended September 30
	Pension benefits						Other benefits						Pension benefits						Other benefits
(in thousands)	2006			2005			2006			2005			2006			2005			2006			2005
Service cost	$	8,200		$	7,354		$	1,277		$	1,316		$	24,454		$	22,027		$	3,822		$	3,934
Interest cost		13,603			13,001			2,616			2,759			40,639			39,090			8,003			8,311
Expected return on plan assets		(18,005	)		(18,569	)		(2,486	)		(2,465	)		(53,679	)		(55,478	)		(7,432	)		(7,390	)
Amortization of unrecognized transition obligation		1			1			785			785			4			3			2,353			2,354
Amortization of prior service cost (gain)		(29	)		(156	)		3			—			(256	)		(467	)		10			—
Recognized actuarial loss		2,965			1,447			43			101			9,090			4,443			369			332

Net periodic benefit cost	$	6,735		$	3,078		$	2,238		$	2,496		$	20,252		$	9,618		$	7,125		$	7,541

Of the net periodic benefit costs, the Company recorded expense of $21 million and $14 million in the first nine 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 (5,096,494 shares available for issuance under outstanding and future grants and awards as of September 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 under the SOIP. 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 equaled 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 prior to and 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 nine months of 2006 and 2005 of $1.3 million and $3.3 million, respectively. In each of the third quarters of 2006 and 2005, the Company recorded share-based compensation expense of $0.4 million. 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 nine months of 2006 and 2005 of $0.6 million and $1.0 million, respectively. In each of the third quarters of 2006 and 2005, the Company recorded related income tax benefits of $0.1 million. The Company has not capitalized any share-based compensation cost.

In place of a SARs grant for 2006, the Company instead awarded restricted stock, as described under “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:


September 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	1.5	$	20.50	6,000	1.5	$	20.50
1999		17.61 - 17.63	65,000	2.8		17.62	65,000	2.8		17.62
2000		14.74	52,000	3.6		14.74	52,000	3.6		14.74
2001		17.96	89,500	4.4		17.96	89,500	4.4		17.96
2002		21.68	150,000	5.4		21.68	150,000	5.4		21.68
2003		20.49	399,500	5.5		20.49	320,500	5.2		20.49

	$	14.74 –21.68	762,000	4.9	$	19.79	683,000	4.8	$	19.71

As of December 31, 2005, NQSOs outstanding totaled 929,000, with a weighted-average exercise price of $19.88. As of September 30, 2006, NQSO shares outstanding and NQSO exercisable had an aggregate intrinsic value (including dividend equivalents) of $9.1 million and $8.3 million, respectively.

NQSO activity and statistics are summarized as follows:


	Three months ended September 30				Nine months ended September 30
($ in thousands, except prices)	2006		2005		2006		2005
Shares granted		—		—		—		—
Shares forfeited		—		—		—		—
Shares expired		—		—		—		—
Shares vested		1,000		—		198,500		277,000
Aggregate fair value of vested shares	$	4		—	$	916	$	1,215
Shares exercised		50,500		17,500		167,000		171,000
Weighted-average exercise price	$	18.04	$	17.93	$	20.32	$	18.90
Cash received from exercise	$	911	$	314	$	3,393	$	3,232
Intrinsic value of shares exercised ¹	$	758	$	275	$	1,931	$	2,106
Tax benefit realized for the deduction of exercises	$	295	$	119	$	751	$	494
Dividend equivalent shares distributed under Section 409A		52		—		43,265		—
Weighted-average Section 409A distribution price	$	27.72		—	$	26.27		—
Intrinsic value of shares distributed under Section 409A	$	1		—	$	1,137		—
Tax benefit realized for Section 409A distributions	$	1		—	$	442		—

¹	Intrinsic value is the amount by which the fair market value of the underlying stock and the related dividend equivalents exceeds the exercise price of the option.

As of September 30, 2006, there was $0.1 million of total unrecognized compensation cost related to nonvested NQSOs and that cost is expected to be recognized over a weighted average period of seven months.

Stock appreciation rights

Information about HEI’s SARs is summarized as follows:


September 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	5.4	$	26.02	235,000	4.5	$	26.02
2005		26.18	554,000	6.8		26.18	164,000	2.7		26.18

	$	26.02 –26.18	879,000	6.3	$	26.12	399,000	3.8	$	26.09

As of December 31, 2005, the shares underlying SARs outstanding totaled 879,000, with a weighted-average exercise price of $26.12. As of September 30, 2006, the SARs outstanding and the SARs exercisable had an aggregate intrinsic value (including dividend equivalents) of $1.9 million and $0.7 million, respectively.

SARs activity and statistics are summarized as follows:


	Three months ended September 30			Nine months ended September 30
($ in thousands, except prices)	2006		2005	2006		2005
Shares granted		—	—		—		554,000
Shares forfeited		—	—		—		—
Shares expired		—	—		—		—
Shares vested		4,000	—		317,750		105,250
Aggregate fair value of vested shares	$	24	—	$	1,773	$	537
Shares exercised		—	—		—		24,000
Weighted-average exercise price		—	—		—	$	26.02
Cash received from exercise		—	—		—		—
Intrinsic value of shares exercised ¹		—	—		—	$	10
Tax benefit realized for the deduction of exercises		—	—		—	$	4
Dividend equivalent shares distributed under Section 409A		94	—		28,600		—
Weighted-average Section 409A distribution price	$	27.72	—	$	26.37		—
Intrinsic value of shares distributed under Section 409A	$	3	—	$	754		—
Tax benefit realized for Section 409A distributions	$	1	—	$	293		—

¹	Intrinsic value is the amount by which the fair market value of the underlying stock and the related dividend equivalents exceeds the exercise price of the option.

As of September 30, 2006, there was $1.2 million of total unrecognized compensation cost related to SARs and that cost is expected to be recognized over a weighted average period of 2.4 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 a result of the changes enacted in Section 409A of the Internal Revenue Code of 1986, as amended (Section 409A), for the nine months ended September 30, 2006 a total of 71,865 dividend equivalent shares for NQSO and SAR grants were distributed to SOIP participants, including those that retired during 2006. Section 409A, which amended the rules on deferred compensation, required the Company to change the way certain affected dividend equivalents are paid in order to avoid significant adverse tax consequences to the SOIP participants. Generally dividend equivalents subject to Section 409A would be paid within 2¹/2 months after the end of the calendar year.

However, upon retirement, an SOIP participant may elect to take distributions of dividend equivalents subject to Section 409A at the time of retirement rather than at the end of the calendar year.

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 September 30, 2006, restricted stock shares outstanding totaled 91,800, with a weighted-average grant date fair value of $25.68. The grant date 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 nine months of 2006, 60,800 shares of restricted stock with a fair market value of $1.6 million were granted, 10,000 shares of restricted stock with a fair market value of $0.2 million vested and no restricted stock shares were forfeited. During the first nine months of 2005, 9,000 shares of restricted stock with a fair market value of $0.2 million were granted and no restricted stock shares vested or were forfeited. During the third quarter of 2006, no restricted stock shares were granted or forfeited and 10,000 shares of restricted stock with a fair market value of $0.2 million vested (with a realized tax benefit for tax deductions of $0.1 million). During the third quarter of 2005, no restricted stock shares of restricted stock were granted, vested or were forfeited. The tax benefit realized for the tax deductions from restricted stock dividends were immaterial for the first nine months of 2006 and 2005.

As of September 30, 2006, there was $1.7 million of total unrecognized compensation cost related to nonvested restricted stock. The cost is expected to be recognized over a period of 3.5 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 nine months ended September 30, 2006 and 2005, the Company paid interest to non-affiliates amounting to $144 million and $127 million, respectively.

For the nine months ended September 30, 2006 and 2005, the Company paid income taxes amounting to $30 million and $21 million, respectively. The difference is primarily due to the federal estimated income taxes paid in the first nine months of 2006 versus none paid in the same period of 2005 (as a result of an overpayment credit from the 2004 tax return applied to the 2005 estimated federal income taxes). This difference was partly offset, however, by additional payments made in the first nine months of 2005 for bank franchise taxes and federal income taxes for a settlement of prior year taxes.

Supplemental disclosures of noncash activities

Noncash increases in common stock for director and officer compensatory plans of the Company were $2.3 million and $4.6 million for the nine months ended September 30, 2006 and 2005, respectively.

In the third quarter of 2006, the Company completed the settlement of net taxes and interest due to the IRS for tax years 1994 through 2002. In a non-cash transaction in the third quarter of 2006, a $30 million deposit made by

the Company in 2005 with the IRS was applied to the net liabilities of $10 million for tax years 1994 through 2002 and $18 million for tax year 2005 with an immaterial net income impact. The remaining $2 million of the 2005 deposit was refunded to the Company.

Revised cash flows from discontinued operations

From December 31, 2005, the Company will separately disclose the operating, investing and financing portions of the cash flows attributable to its discontinued operations, which were previously reported on a combined basis as a single amount. For the first nine 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,” which 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.” SFAS No. 155 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 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.” SFAS No. 156 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. Management does not expect that the impact of adoption 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 resolution 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. Management has not yet determined the impact of adoption 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 FSP No. 13-2 will have no effect on the Company’s financial statements.

Fair value measurements

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for measuring fair value under GAAP and expands disclosures about fair value measurements. SFAS No. 157 applies to fair value measurements that are already required or permitted under existing accounting pronouncements with some exceptions. SFAS No. 157 retains the exchange price notion in defining fair value and clarifies that the exchange price is the price that would be received to sell an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability. It emphasizes that fair value is a market-based, not an entity-specific, measurement based upon the assumptions that market participants would use in pricing an asset or liability. As a basis for considering assumptions in fair value measurements, SFAS No. 157 establishes a hierarchy that gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). SFAS No. 157 expands disclosures about the use of fair value, including disclosure of the level within the hierarchy in which the fair value measurements fall and the effect of the measurements on earnings (or changes in net assets) for the period. SFAS No. 157 must be adopted by the first quarter of the fiscal year beginning after November 15, 2007. The Company plans to adopt SFAS No. 157 on January 1, 2008. Management has not yet determined the impact of adoption, if any, on the Company’s results of operations, financial condition or liquidity.

Effects of prior year misstatements

In September 2006, the SEC staff issued Staff Accounting Bulletin (SAB) No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” which provides guidance on how prior year misstatements should be taken into consideration when quantifying misstatements in current year financial statements for purposes of determining whether the current year’s financial statements are materially misstated. In order to evaluate whether an error is material based on all relevant quantitative and qualitative factors, SAB No. 108 requires the quantification of misstatements using both the income-statement (rollover) and balance sheet (iron curtain) approaches. If the Company does not elect to restate its financial statements for the material misstatements that arise in connection with application of the guidance in SAB No. 108, then for fiscal years ending after November 15, 2006, it must recognize the cumulative effect of applying SAB No. 108 in the current year beginning balances of the affected assets and liabilities with a corresponding adjustment to the current year opening balance in retained earnings. The Company will adopt SAB No. 108 in the

fourth quarter of 2006. Management expects that the impact of adoption, if any, will be immaterial to the Company’s results of operations, financial condition or liquidity.

Planned major maintenance activities

In September 2006, the FASB issued FASB Staff Position (FSP) AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” which eliminates the accrue-in-advance method of accounting for planned major maintenance activities. As a result of the elimination, three methods are currently permitted: (1) direct expensing, (2) built-in overhaul, and (3) deferral. FSP AUG AIR-1 must be adopted by the first fiscal year beginning after December 15, 2006. The Company will adopt FSP AUG AIR-1 on January 1, 2007. Because the Company uses the direct expensing method for planned major maintenance activities, management does not expect any impact of adoption on the Company’s results of operations, financial condition or liquidity.

Defined benefit pension and other postretirement plans

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R),” which requires employers to recognize on their balance sheets the funded status of defined benefit pension and other postretirement benefit plans. Employers will recognize actuarial gains and losses, prior service cost, and any remaining transition amounts from the initial application of SFAS Nos. 87 and 106 when recognizing a plan’s funded status, with the offset to accumulated other comprehensive income (AOCI) in stockholders’ equity. SFAS No. 158 must be adopted in fiscal years ending after December 15, 2006. Accordingly, the Company will adopt SFAS No. 158 on December 31, 2006.

The Company sponsors defined benefit plans (with fiscal year-end measurement dates) and expects to report increased liabilities at year end, with corresponding charges to AOCI. The actual amount recorded will be dependent on numerous factors, including the year-end discount rate assumption, asset returns experienced in 2006, any changes to actuarial assumptions or plan provisions, and contributions made by the Company to the plans during 2006.

If SFAS No. 158 were applied as of December 31, 2005, the Company would have had to recognize additional pension and other postretirement benefit obligations of approximately $184 million and write off $122 million of pension-related intangible and prepaid assets as of December 31, 2005. The Company would also have been required to record a deferred tax benefit associated with the temporary differences between the liabilities recognized for book and tax purposes. The net charge to AOCI would have been $187 million ($4 million, $170 million and $13 million for HEI corporate, consolidated HECO and ASB, respectively) as of December 31, 2005.

The electric utilities plan to update their application in the AOCI Docket to take into account SFAS No. 158 in seeking PUC approval to record as a regulatory asset the amount that would otherwise be charged against stockholders’ equity. If their request is granted, the utilities would seek to include the regulatory asset in their rate bases in their rate cases. 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 SFAS No. 158 on stockholders’ equity or net income. If the PUC were not to grant regulatory asset treatment in the AOCI Docket as updated for SFAS No. 158, there could be a material negative impact to stockholders’ equity. Although there would not be an immediate impact on net income due to the non-regulatory asset treatment, if the electric utilities are required to record substantial charges against stockholders’ equity, their reported returns on rate base and returns on average common equity could increase, which could impact the rates they are allowed to charge and ultimately result in reduced revenues and lower earnings. Further potential negative impacts include the fact that the consolidated adjusted debt to capitalization and interest coverage ratios of the Company and the electric utilities may deteriorate, which could result in security ratings downgrades and difficulty or greater expense in obtaining future financing. If the electric utilities are not allowed regulatory asset treatment for the amounts that would be charged to AOCI, however, they still would seek a return on their prepaid pension assets (by inclusion in rate base) in their respective rate cases.

(10) Income taxes

In the first quarter of 2005, the Company recorded a $2 million reserve, net of taxes, for interest the Company might incur 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 other audit issues with the 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 September 30, 2006, the Company had reserved $1 million, net of tax effects, 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 September 30, 2006, HEI Properties, Inc. (HEIPI) held shares of Hoku Scientific, Inc. (Hoku), a materials science company focused on clean energy technologies. 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. 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 nine months ended September 30, 2006, HEIPI recognized a $0.4 million gain and a $1.3 million loss (unrealized and realized, net of taxes), respectively, on the Hoku shares. As of September 30, 2006, HEIPI had sold 27% of its Hoku shares and carried its remaining investment in Hoku shares at $2 million.

(12) Credit agreements

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 customary conditions which must be met in order to draw on the credit facility, including the continued accuracy of HEI’s representations and compliance with its covenants. In addition to customary defaults, HEI’s failure to maintain its nonconsolidated “Capitalization Ratio” (funded debt) of 50% or less and “Consolidated Net Worth” of $850 million, as defined in its agreement, or meet other requirements will result in an event of default.

Also effective April 3, 2006, HEI entered into a $75 million bilateral revolving unsecured credit agreement with Merrill Lynch Bank USA, which was subsequently terminated effective August 11, 2006.

The syndicated credit facility is maintained to support the issuance of commercial paper, but also may be drawn for general corporate purposes. The facility contains 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 facility. The Company used the April 3, 2006 facilities to support the issuance of commercial paper to temporarily refinance $100 million of its Series C medium-term notes, which matured on April 10, 2006. On August 8, 2006, HEI completed the sale of $100 million of 6.141% Medium-Term Notes, Series D due August 15, 2011, the proceeds of which were ultimately used to reduce HEI’s outstanding commercial paper as it matured. As of October 31, 2006, the $100 million credit facility remained undrawn.

See Note 9 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)	September 30, 2006			December 31, 2005
Assets
Utility plant, at cost
Land	$	35,035		$	33,034
Plant and equipment		3,874,525			3,749,386
Less accumulated depreciation		(1,534,682	)		(1,456,537	)
Plant acquisition adjustment, net		106			145
Construction in progress		160,300			147,756

Net utility plant		2,535,284			2,473,784

Current assets
Cash and equivalents		4,418			143
Customer accounts receivable, net		139,808			123,895
Accrued unbilled revenues, net		98,689			91,321
Other accounts receivable, net		6,037			14,761
Fuel oil stock, at average cost		95,970			85,450
Materials and supplies, at average cost		30,297			26,974
Prepaid pension benefit cost		91,292			106,318
Other		9,890			8,584

Total current assets		476,401			457,446

Other long-term assets
Regulatory assets		110,335			110,718
Unamortized debt expense		13,896			14,361
Other		29,356			25,152

Total other long-term assets		153,587			150,231

	$	3,165,272		$	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		687,245			654,686

Common stock equity		1,071,818			1,039,259
Cumulative preferred stock – not subject to mandatory redemption		34,293			34,293
Long-term debt, net		766,137			765,993

Total capitalization		1,872,248			1,839,545

Current liabilities
Short-term borrowings–nonaffiliates		145,080			136,165
Accounts payable		107,348			122,201
Interest and preferred dividends payable		15,905			9,990
Taxes accrued		163,896			133,583
Other		36,610			37,132

Total current liabilities		468,839			439,071

Deferred credits and other liabilities
Deferred income taxes		200,523			208,374
Regulatory liabilities		235,480			219,204
Unamortized tax credits		57,373			55,327
Other		65,070			63,677

Total deferred credits and other liabilities		558,446			546,582

Contributions in aid of construction		265,739			256,263

	$	3,165,272		$	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 September 30						Nine months ended September 30
(in thousands, except for ratio of earnings to fixed charges)	2006			2005			2006			2005
Operating revenues	$	568,236		$	489,877		$	1,545,557		$	1,292,374
Operating expenses
Fuel oil		227,288			182,663			594,940			447,064
Purchased power		138,758			122,086			378,916			329,671
Other operation		46,612			41,974			136,565			125,084
Maintenance		23,653			21,141			63,087			58,916
Depreciation		32,539			30,655			97,614			92,297
Taxes, other than income taxes		51,985			44,990			142,726			120,254
Income taxes		14,665			13,754			38,909			33,785

		535,500			457,263			1,452,757			1,207,071

Operating income		32,736			32,614			92,800			85,303

Other income
Allowance for equity funds used during construction		1,838			1,406			4,974			3,675
Other, net		1,379			1,191			2,809			2,811

		3,217			2,597			7,783			6,486

Income before interest and other charges		35,953			35,211			100,583			91,789

Interest and other charges
Interest on long-term debt		10,777			10,731			32,331			32,296
Amortization of net bond premium and expense		565			545			1,651			1,658
Other interest charges		1,285			1,408			5,424			3,183
Allowance for borrowed funds used during construction		(838	)		(558	)		(2,259	)		(1,460	)
Preferred stock dividends of subsidiaries		228			228			686			686

		12,017			12,354			37,833			36,363

Income before preferred stock dividends of HECO		23,936			22,857			62,750			55,426
Preferred stock dividends of HECO		270			270			810			810

Net income for common stock	$	23,666		$	22,587		$	61,940		$	54,616

Ratio of earnings to fixed charges (SEC method)								3.36			3.24

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Retained Earnings (unaudited)


	Three months ended September 30					Nine months ended September 30
(in thousands)	2006		2005			2006			2005
Retained earnings, beginning of period	$	663,579	$	645,586		$	654,686		$	632,779
Net income for common stock		23,666		22,587			61,940			54,616
Common stock dividends		—		(14,733	)		(29,381	)		(33,955	)

Retained earnings, end of period	$	687,245	$	653,440		$	687,245		$	653,440

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

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)


Nine months ended September 30	2006			2005
(in thousands)
Cash flows from operating activities
Income before preferred stock dividends of HECO	$	62,750		$	55,426
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities
Depreciation of property, plant and equipment		97,614			92,297
Other amortization		5,907			6,675
Deferred income taxes		(7,851	)		17,935
Tax credits, net		2,990			1,800
Allowance for equity funds used during construction		(4,974	)		(3,675	)
Changes in assets and liabilities
Increase in accounts receivable		(7,189	)		(14,938	)
Increase in accrued unbilled revenues		(7,368	)		(11,153	)
Increase in fuel oil stock		(10,520	)		(19,208	)
Increase in materials and supplies		(3,323	)		(3,121	)
Decrease in prepaid pension benefit cost		15,026			5,400
Increase in regulatory assets		(2,296	)		(2,815	)
Decrease in accounts payable		(14,853	)		(970	)
Increase in taxes accrued		30,313			10,616
Changes in other assets and liabilities		(2,719	)		(9,138	)

Net cash provided by operating activities		153,507			125,131

Cash flows from investing activities
Capital expenditures		(137,345	)		(142,573	)
Contributions in aid of construction		13,227			10,274
Other		407			1,476

Net cash used in investing activities		(123,711	)		(130,823	)

Cash flows from financing activities
Common stock dividends		(29,381	)		(33,955	)
Preferred stock dividends		(810	)		(810	)
Proceeds from issuance of long-term debt		—			58,525
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		8,915			36,433
Other		(4,245	)		(4,925	)

Net cash provided by (used in) financing activities		(25,521	)		8,268

Net increase in cash and equivalents		4,275			2,576
Cash and equivalents, beginning of period		143			327

Cash and equivalents, end of period	$	4,418		$	2,903

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 included in HECO’s Quarterly Reports on SEC Form 10-Q for the quarters ended March 31, 2006 and June 30, 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 September 30, 2006 and December 31, 2005, the results of their operations for the three and nine months ended September 30, 2006 and 2005 and their cash flows for the nine months ended September 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 September 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 nine months ended September 30, 2006 and 2005 each consisted of $2.5 million of interest income received from the 2004 Debentures; $2.4 million of distributions to holders of the Trust Preferred Securities; and $0.1 million of common dividends on the trust common securities to HECO. So long as the 2004 Trust Preferred Securities are outstanding, HECO is not entitled to receive any funds from Trust III other than pro rata distributions, subject to certain subordination provisions, on the trust common securities. In the event of a default by HECO in the performance of its obligations under the 2004 Debentures or under its Guarantees, or in the event HECO, HELCO or MECO elect to defer payment

of interest on any of their respective 2004 Debentures, then HECO will be subject to a number of restrictions, including a prohibition on the payment of dividends on its common stock.

Purchase power agreements

As of September 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 nine months ended September 30, 2006 totaled $379 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $98 million, $137 million, $52 million and $32 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, subsequently approved by the PUC, 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 to the PPA, subsequently approved by the PUC, which together effectively increased the firm capacity from 180 MW to 208 MW. 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 (PURPA).

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 currently 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 completed the installation of a 30 MW windfarm on Maui and began selling power to MECO in June 2006. Management 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. Apollo has informed HELCO that it can meet the April 2007 target for commercial operation. The restated and amended 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 the 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 available at this time, management currently 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 restated and amended PPA, the impact of a required consolidation of Apollo could be material. If HELCO determines it is required to consolidate the financial statements of Apollo and such consolidation has 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 nine months ended September 30, 2006 and 2005, HECO and its subsidiaries included approximately $137 million and $114 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

(4) Retirement benefits

In each of the first nine months of 2006 and 2005, HECO and its subsidiaries paid contributions of $8 million to their retirement benefit plans. HECO and its subsidiaries’ current estimate of contributions to their retirement benefit plans in 2006 is $10 million, compared to contributions of $18 million in 2005.

The components of net periodic benefit cost were as follows:


	Three months ended September 30												Nine months ended September 30
	Pension benefits						Other benefits						Pension benefits						Other benefits
(in thousands)	2006			2005			2006			2005			2006			2005			2006			2005
Service cost	$	6,749		$	5,969		$	1,244		$	1,280		$	19,970		$	17,873		$	3,721		$	3,824
Interest cost		12,111			11,675			2,547			2,694			36,237			35,113			7,790			8,114
Expected return on plan assets		(16,208	)		(16,847	)		(2,445	)		(2,428	)		(48,257	)		(50,309	)		(7,312	)		(7,278	)
Amortization of unrecognized transition obligation		1			1			782			782			2			2			2,347			2,347
Amortization of prior service gain		(193	)		(192	)		—			—			(578	)		(577	)		—			—
Recognized actuarial loss		2,655			1,150			39			90			8,043			3,552			349			296

Net periodic benefit cost	$	5,115		$	1,756		$	2,167		$	2,418		$	15,417		$	5,654		$	6,895		$	7,303

Of the net periodic benefit costs, HECO and its subsidiaries recorded expense of $16 million and $10 million in the first nine 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 September 30, 2006, HECO and its subsidiaries had recognized $71 million of revenues with respect to interim orders ($19 million related to interim orders regarding certain integrated resource planning costs and $52 million related to the interim order with respect to Oahu’s general rate increase request based on a 2005 test year 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 based on a 2005 test year, 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, Act 162 requires that these five specific factors 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 that the PUC not review the Act 162 ECAC issues in the pending rate case based on a 2005 test year since HECO’s application was filed and the

record in the proceeding was completed before Act 162 was signed into law, and the settlement agreement entered into by the parties in the rate case included a provision allowing the existing ECAC to be continued. On August 7, 2006, an amended stipulation was filed in substantially the same form as the June 30, 2006 stipulation, but also included the DOD. Management cannot predict whether the PUC will accept the disposition of the Act 162 issue proposed in the amended stipulation or, if not, the procedural steps or procedural schedule that will be adopted to address the issues that are raised by Act 162 or the timing of the PUC’s issuance of a final D&O in HECO’s pending rate case based on a 2005 test year.

The ECAC provisions of Act 162 will be reviewed in the HELCO rate case based on a 2006 test year, as well as in future rate cases HECO and MECO intend to file.

Management cannot predict the ultimate outcome or the effect of these Act 162 issues on the operation of the ECAC as it relates to the electric utilities.

HELCO power situation

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.” As a result of the final resolution of the proceedings described below, CT-4 and CT-5 are now operational, there are no pending lawsuits involving the project, and work on ST-7 is proceeding. In May 2006, HELCO filed a rate increase application based on a 2006 test year seeking to recover, among other things, CT-4 and CT-5 costs.

Historical context. 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 opposed 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, HELCO installed CT-4 and CT-5 and put them into limited commercial operation in May and June 2004, respectively. HELCO met the Board of Land and Natural Resources’ (BLNR’s) construction deadline of July 31, 2005. Noise mitigation equipment has been installed on CT-4 and CT-5 and additional noise mitigation work is planned 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 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.

The Hawaii Supreme Court has issued favorable decisions on all four 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 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. In the fourth appeal, on September 21, 2006, the Hawaii Supreme Court affirmed the Third Circuit Court’s decision upholding the BLNR’s approval of the long-term lease allowing HELCO to use brackish well water.

In addition to the Supreme Court appeals, one Circuit Court matter had remained open, but it was inactive after the mediation that resulted in the Settlement Agreement. With all appeals resolved, the stipulation to dismiss this case was filed on October 5, 2006 and the case was dismissed with prejudice on October 6, 2006. Full implementation of the Settlement Agreement was conditioned on obtaining final dispositions, which have now been obtained, of all litigation pending at the time of the Settlement Agreement.

The Settlement Agreement required 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 had commenced well before all of the litigation was resolved.

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 boundary amendment was approved in October 2005. In May 2006, HELCO obtained the County of Hawaii 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. Management believes that any other required permits will be obtained and HELCO will now commence certain ST-7 construction work.

Costs incurred; management’s evaluation. As of September 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 ($103 million) and 2005 ($7 million) and depreciated beginning January 1 of the year following the reclassification.

HELCO’s electric rates will not change as a result of including CT-4 and CT-5 in plant and equipment unless and until the PUC grants rate relief in the HELCO rate case based on a 2006 test year 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 September 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. However, in June 2002, an application for a permit which would have allowed construction in the originally planned route through conservation district lands was denied.

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 for the revised EOTP 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 September 30, 2006, the accumulated costs recorded for the EOTP amounted to $29 million, including (i) $12 million of planning and permitting costs incurred prior to the denial in 2002 of the approval necessary for the partial underground/partial overhead 138 kV line, (ii) $5 million of planning and permitting costs incurred after 2002 and (iii) $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 November 2005 evidentiary hearing, the PUC approved that part of a stipulation between HECO and the Consumer Advocate providing that (i) this proceeding should determine whether HECO should be given approval to expend funds for the EOTP, but with the understanding 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 (ii) 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 September 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 or 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 for the sites comprising the Iwilei Unit, which analyses will identify and recommend remedial approaches for consideration by the DOH.

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 $0.7 million has been incurred through September 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 (such as its Honolulu power plant, which is located in the “Downtown” unit of the Honolulu Harbor site), the cost estimate may be subject to significant change and additional material investigative and remedial costs may be incurred.

In 2003, HECO and other members of the IDPP with active operations in the Iwilei area investigated their operations to evaluate whether their facilities were active sources of petroleum in the area. HECO’s investigation concluded that its facilities were not releasing petroleum. Routine maintenance and inspections of HECO facilities since then confirm that they are not currently 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 its 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 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 currently collecting data necessary to prepare the comprehensive demonstration study that will evaluate which compliance options are available for the Company, some of which could entail significant capital expenditures to implement.

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 each of the nine months ended September 30, 2006 and 2005, HECO and its subsidiaries paid interest amounting to $30 million.

For the nine months ended September 30, 2006 and 2005, HECO and its subsidiaries paid income taxes amounting to $17 million and $5 million, respectively. The difference is primarily due to the federal estimated income taxes paid in the first nine months of 2006 versus none paid in the same period of 2005 (as a result of an overpayment credit from the 2004 tax return applied to the 2005 estimated federal income taxes).

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 $5.0 million and $3.7 million for the nine months ended September 30, 2006 and 2005, respectively.

(7) Recent accounting pronouncements and interpretations

For a discussion of recent accounting pronouncements and interpretations regarding the accounting treatment of uncertainty in income taxes, fair value measurements, effects of prior year misstatements, planned major maintenance activities and balance sheet recognition of the funded status of defined benefit pension and other postretirement benefit plans, 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) Reconciliation of electric utility operating income per HEI and HECO consolidated statements of income


	Three months ended September 30						Nine months ended September 30
(in thousands)	2006			2005			2006			2005
Operating income from regulated and nonregulated activities before income taxes (per HEI consolidated statements of income)	$	48,651		$	47,533		$	134,077		$	121,786
Deduct:
Income taxes on regulated activities		(14,665	)		(13,754	)		(38,909	)		(33,785	)
Revenues from nonregulated activities		(1,602	)		(1,462	)		(3,304	)		(3,470	)
Add: Expenses from nonregulated activities		352			297			936			772

Operating income from regulated activities after income taxes (per HECO consolidated statements of income)	$	32,736		$	32,614		$	92,800		$	85,303

(9) Credit agreement

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. On August 30, 2006, HECO filed an application with the PUC requesting approval to maintain the $175 million credit facility for five years, which, if approved by the PUC, will automatically extend the termination date of the credit facility from March 29, 2007 to March 31, 2011. 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 and customary conditions that must be met in order to draw on it, including the continued accuracy of HECO’s representations and compliance with several covenants. In addition to customary defaults, an event of default would result if HECO fails to maintain a “Consolidated Capitalization Ratio” (equity) of at least 35%, as defined in its agreement, if HECO’s or any of its subsidiaries’ guarantee of additional indebtedness of the subsidiaries would cause the subsidiary’s Consolidated Subsidiary Funded Debt to Capitalization Ratio to exceed 65%, as defined in its agreement, or if HECO fails to meet other requirements.

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. As of October 31, 2006, the $175 million of credit facilities remained undrawn.

(10) Consolidating financial information

HECO is not required to provide separate financial statements or 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)

September 30, 2006


(in thousands)	HECO			HELCO		MECO		RHI	Reclassi- fications and elimina- tions		HECO consoli- dated
Assets
Utility plant, at cost
Land	$	25,779		4,910		4,346		—	—		$	35,035
Plant and equipment		2,392,147		785,228		697,150		—	—			3,874,525
Less accumulated depreciation		(938,647	)	(294,662	)	(301,373	)	—	—			(1,534,682	)
Plant acquisition adjustment, net		—		—		106		—	—			106
Construction in progress		82,945		17,687		59,668		—	—			160,300

Net utility plant		1,562,224		513,163		459,897		—	—			2,535,284

Investment in subsidiaries, at equity		396,027		—		—		—	(396,027	)		—

Current assets
Cash and equivalents		1,946		711		1,467		294	—			4,418
Advances to affiliates		61,650		—		—		—	(61,650	)		—
Customer accounts receivable, net		93,997		24,415		21,396		—	—			139,808
Accrued unbilled revenues, net		67,237		16,507		14,945		—	—			98,689
Other accounts receivable, net		4,486		677		1,180		—	(306	)		6,037
Fuel oil stock, at average cost		68,618		10,098		17,254		—	—			95,970
Materials and supplies, at average cost		14,729		4,177		11,391		—	—			30,297
Prepaid pension benefit cost		71,833		13,464		5,995		—	—			91,292
Other		8,185		1,480		225		—	—			9,890

Total current assets		392,681		71,529		73,853		294	(61,956	)		476,401

Other long-term assets
Regulatory assets		81,168		14,120		15,047		—	—			110,335
Unamortized debt expense		9,460		2,315		2,121		—	—			13,896
Other		21,849		3,455		4,052		—	—			29,356

Total other long-term assets		112,477		19,890		21,220		—	—			153,587

	$	2,463,409		604,582		554,970		294	(457,983	)	$	3,165,272

Capitalization and liabilities
Capitalization
Common stock equity	$	1,071,818		193,885		201,858		284	(396,027	)	$	1,071,818
Cumulative preferred stock—not subject to mandatory redemption		22,293		7,000		5,000		—	—			34,293
Long-term debt, net		481,213		131,036		153,888		—	—			766,137

Total capitalization		1,575,324		331,921		360,746		284	(396,027	)		1,872,248

Current liabilities
Short-term borrowings—nonaffiliates		145,080		—		—		—	—			145,080
Short-term borrowings—affiliate		—		46,900		14,750		—	(61,650	)		—
Accounts payable		74,238		17,260		15,850		—	—			107,348
Interest and preferred dividends payable		10,180		2,970		3,004		—	(249	)		15,905
Taxes accrued		104,660		29,477		29,759		—	—			163,896
Other		24,749		3,690		8,218		10	(57	)		36,610

Total current liabilities		358,907		100,297		71,581		10	(61,956	)		468,839

Deferred credits and other liabilities
Deferred income taxes		155,422		24,626		20,475		—	—			200,523
Regulatory liabilities		160,808		42,864		31,808		—	—			235,480
Unamortized tax credits		32,378		12,913		12,082		—	—			57,373
Other		21,304		35,016		8,750		—	—			65,070

Total deferred credits and other liabilities		369,912		115,419		73,115		—	—			558,446

Contributions in aid of construction		159,266		56,945		49,528		—	—			265,739

	$	2,463,409		604,582		554,970		294	(457,983	)	$	3,165,272

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

December 31, 2005


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

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

Investment in 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 September 30, 2006


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Operating revenues	$	376,925		94,088		97,223		—		—		$	568,236

Operating expenses
Fuel oil		150,868		24,723		51,697		—		—			227,288
Purchased power		96,038		33,315		9,405		—		—			138,758
Other operation		32,344		6,935		7,333		—		—			46,612
Maintenance		14,494		5,062		4,097		—		—			23,653
Depreciation		18,702		7,429		6,408		—		—			32,539
Taxes, other than income taxes		34,492		8,584		8,909		—		—			51,985
Income taxes		9,388		2,160		3,117		—		—			14,665

		356,326		88,208		90,966		—		—			535,500

Operating income		20,599		5,880		6,257		—		—			32,736

Other income
Allowance for equity funds used during construction		1,009		63		766		—		—			1,838
Equity in earnings of subsidiaries		8,375		—		—		—		(8,375	)		—
Other, net		1,630		111		467		(32	)	(797	)		1,379

		11,014		174		1,233		(32	)	(9,172	)		3,217

Income (loss) before interest and other charges		31,613		6,054		7,490		(32	)	(9,172	)		35,953

Interest and other charges
Interest on long-term debt		6,741		1,809		2,227		—		—			10,777
Amortization of net bond premium and expense		354		108		103		—		—			565
Other interest charges		1,034		600		448		—		(797	)		1,285
Allowance for borrowed funds used during construction		(452	)	(29	)	(357	)	—		—			(838	)
Preferred stock dividends of subsidiaries		—		—		—		—		228			228

		7,677		2,488		2,421		—		(569	)		12,017

Income (loss) before preferred stock dividends of HECO		23,936		3,566		5,069		(32	)	(8,603	)		23,936
Preferred stock dividends of HECO		270		133		95		—		(228	)		270

Net income (loss) for common stock	$	23,666		3,433		4,974		(32	)	(8,375	)	$	23,666

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Retained Earnings (unaudited)

Three months ended September 30, 2006


(in thousands)	HECO		HELCO	MECO	RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Retained earnings, beginning of period	$	663,579	89,808	101,963	(465	)	(191,306	)	$	663,579
Net income (loss) for common stock		23,666	3,433	4,974	(32	)	(8,375	)		23,666
Common stock dividends		—	—	—	—		—			—

Retained earnings, end of period	$	687,245	93,241	106,937	(497	)	(199,681	)	$	687,245

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Three months ended September 30, 2005


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Operating revenues	$	330,922		79,511		79,444		—		—		$	489,877

Operating expenses
Fuel oil		124,427		16,799		41,437		—		—			182,663
Purchased power		89,021		29,015		4,050		—		—			122,086
Other operation		28,809		6,454		6,711		—		—			41,974
Maintenance		14,157		4,250		2,734		—		—			21,141
Depreciation		17,583		6,804		6,268		—		—			30,655
Taxes, other than income taxes		30,411		7,252		7,327		—		—			44,990
Income taxes		7,962		2,413		3,379		—		—			13,754

		312,370		72,987		71,906		—		—			457,263

Operating income		18,552		6,524		7,538		—		—			32,614

Other income
Allowance for equity funds used during construction		1,051		95		260		—		—			1,406
Equity in earnings of subsidiaries		9,768		—		—		—		(9,768	)		—
Other, net		1,436		103		192		(50	)	(490	)		1,191

		12,255		198		452		(50	)	(10,258	)		2,597

Income (loss) before interest and other charges		30,807		6,722		7,990		(50	)	(10,258	)		35,211

Interest and other charges
Interest on long-term debt		6,695		1,809		2,227		—		—			10,731
Amortization of net bond premium and expense		343		98		104		—		—			545
Other interest charges		1,319		475		104		—		(490	)		1,408
Allowance for borrowed funds used during construction		(407	)	(38	)	(113	)	—		—			(558	)
Preferred stock dividends of subsidiaries		—		—		—		—		228			228

		7,950		2,344

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