HAWAIIAN ELECTRIC CO INC - Quarter Report: 2007 September (Form 10-Q)

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2007

¨	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 29, 2007
Hawaiian Electric Industries, Inc. (Without Par Value)		83,040,566 Shares
Hawaiian Electric Company, Inc. ($6²/3 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, 2007

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 Statements of Income (unaudited) - three and nine months ended September 30, 2007 and 2006	1
	Consolidated Balance Sheets (unaudited) - September 30, 2007 and December 31, 2006	2
	Consolidated Statements of Changes in Stockholders’ Equity (unaudited) - nine months ended September 30, 2007 and 2006	3
	Consolidated Statements of Cash Flows (unaudited) - nine months ended September 30, 2007 and 2006	4
	Notes to Consolidated Financial Statements (unaudited)	5

	Hawaiian Electric Company, Inc. and Subsidiaries
	Consolidated Statements of Income (unaudited) - three and nine months ended September 30, 2007 and 2006	16
	Consolidated Balance Sheets (unaudited) - September 30, 2007 and December 31, 2006	17
	Consolidated Statements of Changes in Stockholder’s Equity (unaudited) - nine months ended September 30, 2007 and 2006	18
	Consolidated Statements of Cash Flows (unaudited) - nine months ended September 30, 2007 and 2006	19
	Notes to Consolidated Financial Statements (unaudited)	20
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	42
	HEI Consolidated	42
	Electric Utilities	49
	Bank	71
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	77
Item 4.	Controls and Procedures	78
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	79
Item 1A.	Risk Factors	79
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	79
Item 5.	Other Information	79
Item 6.	Exhibits	85
Signatures		86

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended September 30, 2007

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.). AdCommunications, Inc. (dissolved in May 2007) is a former subsidiary.
CHP		Combined heat and power
Company		Hawaiian Electric Industries, Inc. and its direct and indirect subsidiaries, including, without limitation, Hawaiian Electric Company, Inc., Hawaii Electric Light Company, Inc., Maui Electric Company, Limited, HECO Capital Trust III (unconsolidated subsidiary), Renewable Hawaii, Inc., Uluwehiokama Biofuels Corp., HEI Diversified, Inc., American Savings Bank, F.S.B. and its subsidiaries, Pacific Energy Conservation Services, Inc., HEI Properties, Inc., HEI Investments, Inc., Hycap Management, Inc. (in dissolution), Hawaiian Electric Industries Capital Trust II (unconsolidated subsidiary), Hawaiian Electric Industries Capital Trust III (unconsolidated subsidiary) and The Old Oahu Tug Service, Inc. Former subsidiaries include HEIPC (discontinued operations, dissolved in 2006) and its dissolved 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 No.
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 Hawaii Electric Light Company, Inc., Maui Electric Company, Limited, HECO Capital Trust III (unconsolidated subsidiary), Renewable Hawaii, Inc. and Uluwehiokama Biofuels Corp.

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., HEI Investments, Inc., Hycap Management, Inc. (in dissolution), Hawaiian Electric Industries Capital Trust II (unconsolidated subsidiary), Hawaiian Electric Industries Capital Trust III (unconsolidated subsidiary) and The Old Oahu Tug Service, Inc. Former subsidiaries include HEI Power Corp. (discontinued operations, dissolved in 2006).
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 formerly wholly owned subsidiary of Hawaiian Electric Industries, Inc., and the former 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 was dissolved in December 2006.
HEIRSP		Hawaiian Electric Industries Retirement Savings Plan
HELCO		Hawaii Electric Light Company, Inc., an electric utility subsidiary of Hawaiian Electric Company, Inc.
HPOWER		City and County of Honolulu with respect to a power purchase agreement for a refuse-fired plant
IPP		Independent power producer
IRP		Integrated resource plan
KWH		Kilowatthour
MECO		Maui Electric Company, Limited, an electric utility subsidiary of Hawaiian Electric Company, Inc.
MW		Megawatt/s (as applicable)
NII		Net interest income
NPV		Net portfolio value
NQSO		Nonqualified stock options
O&M		Operation and maintenance
OPEB		Postretirement benefits other than pensions
PPA		Power purchase agreement
PRPs		Potentially responsible parties
PUC		Public Utilities Commission of the State of Hawaii
RHI		Renewable Hawaii, Inc., a wholly owned subsidiary of Hawaiian Electric Company, Inc.
ROACE		Return on average common equity
ROR		Return on average rate base
SARs		Stock appreciation rights
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.
UBC		Uluwehiokama Biofuels Corp., a newly formed, non-regulated subsidiary of Hawaiian Electric Company, 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, tsunamis and the potential effects of global warming;

•

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, 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 peak reserve margins on Oahu continue 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 (ECACs);

•

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, ASB and their subsidiaries (including changes in taxation, environmental laws and regulations, the potential regulation of greenhouse gas emissions and governmental fees and assessments); decisions by the Public Utilities Commission of the State of Hawaii (PUC) in rate cases (including decisions on ECACs) and other proceedings and by other agencies and courts on land use, environmental and other permitting issues (such as required corrective actions, restrictions and penalties that may arise, for example with respect to environmental conditions or renewable portfolio standards (RPS)); enforcement actions by the OTS and other governmental authorities (such as required corrective actions, restrictions and penalties that may arise, for example, with respect to compliance deficiencies under the Bank Secrecy Act or other regulatory requirements or with respect to capital adequacy);

•

increasing operation and maintenance expenses for the electric utilities, resulting in the need for more frequent rate cases, and increasing noninterest expenses at ASB;

•

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

•

the effects of changes in accounting principles applicable to HEI, HECO, ASB 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 PPAs 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, ASB 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, HECO, ASB and their 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 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
	2007			2006			2007			2006
Revenues
Electric utility	$	567,615		$	569,838		$	1,508,005		$	1,548,861
Bank		105,507			103,338			317,493			305,898
Other		339			718			2,749			(934	)

		673,461			673,894			1,828,247			1,853,825

Expenses
Electric utility		536,249			521,187			1,434,858			1,414,784
Bank		86,960			82,760			260,824			232,146
Other		2,235			3,591			10,698			10,659

		625,444			607,538			1,706,380			1,657,589

Operating income (loss)
Electric utility		31,366			48,651			73,147			134,077
Bank		18,547			20,578			56,669			73,752
Other		(1,896	)		(2,873	)		(7,949	)		(11,593	)

		48,017			66,356			121,867			196,236

Interest expense—other than on deposit liabilities and other bank borrowings		(19,589	)		(18,275	)		(59,382	)		(56,526	)
Allowance for borrowed funds used during construction		656			838			1,840			2,259
Preferred stock dividends of subsidiaries		(474	)		(471	)		(1,420	)		(1,417	)
Allowance for equity funds used during construction		1,336			1,838			3,770			4,974

Income from before income taxes		29,946			50,286			66,675			145,526
Income taxes		10,065			17,963			22,481			53,642

Net income	$	19,881		$	32,323		$	44,194		$	91,884

Basic earnings per common share	$	0.24		$	0.40		$	0.54		$	1.13

Diluted earnings per common share	$	0.24		$	0.40		$	0.54		$	1.13

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

Weighted-average number of common shares outstanding		82,481			81,213			81,949			81,099
Dilutive effect of stock options and dividend equivalents		159			343			231			284

Adjusted weighted-average shares		82,640			81,556			82,180			81,383

Ratio of earnings to fixed charges (SEC method)
Excluding interest on ASB deposits								1.53			2.23

Including interest on ASB deposits								1.35			1.85

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

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)


(dollars in thousands)	September 30, 2007			December 31, 2006
Assets
Cash and equivalents	$	167,020		$	177,630
Federal funds sold		59,009			79,671
Accounts receivable and unbilled revenues, net		276,786			248,639
Available-for-sale investment and mortgage-related securities		2,160,841			2,367,427
Investment in stock of Federal Home Loan Bank of Seattle, at cost		97,764			97,764
Loans receivable, net		4,020,112			3,780,461
Property, plant and equipment, net of accumulated depreciation of $1,735,790 and $1,651,088		2,686,584			2,647,490
Regulatory assets		142,675			112,349
Other		334,186			292,638
Goodwill and other intangibles, net		85,622			87,140

	$	10,030,599		$	9,891,209

Liabilities and stockholders’ equity
Liabilities
Accounts payable	$	219,737		$	165,505
Deposit liabilities		4,387,206			4,575,548
Short-term borrowings—other than bank		101,097			176,272
Other bank borrowings		1,731,799			1,568,585
Long-term debt, net—other than bank		1,229,949			1,133,185
Deferred income taxes		95,462			106,780
Regulatory liabilities		257,817			240,619
Contributions in aid of construction		286,403			276,728
Other		556,412			518,454

		8,865,882			8,761,676

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 200,000,000 shares; issued and outstanding: 82,957,753 shares and 81,461,409 shares		1,061,191			1,028,101
Retained earnings		210,344			242,667
Accumulated other comprehensive loss, net of tax benefits		(141,111	)		(175,528	)

		1,130,424			1,095,240

	$	10,030,599		$	9,891,209

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, 2006	81,461	$	1,028,101	$	242,667		$	(175,528	)	$	1,095,240
Comprehensive income:
Net income	—		—		44,194			—			44,194
Net unrealized gains on securities arising during the period, net of taxes of $6,748	—		—		—			10,219			10,219
Defined benefit retirement plans - amortization of net loss, prior service cost and transition obligation included in net periodic benefit cost, net of taxes of $3,825	—		—		—			5,993			5,993

Comprehensive income	—		—		44,194			16,212			60,406

Adjustment to initially apply a PUC interim D&O related to defined benefit retirement plans, net of taxes of $11,595	—		—		—			18,205			18,205
Adjustment to initially apply FIN 48	—		—		(228	)		—			(228	)
Issuance of common stock, net	1,497		33,090		—			—			33,090
Common stock dividends ($0.93 per share)	—		—		(76,289	)		—			(76,289	)

Balance, September 30, 2007	82,958	$	1,061,191	$	210,344		$	(141,111	)	$	1,130,424


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 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

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	2007			2006
(in thousands)
Cash flows from operating activities
Net income	$	44,194		$	91,884
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment		111,007			105,862
Other amortization		9,275			7,790
Writedown of utility plant		11,701			—
Provision for loan losses		3,900			—
Deferred income taxes		(18,068	)		(8,961	)
Allowance for equity funds used during construction		(3,770	)		(4,974	)
Excess tax benefits from share-based payment arrangements		(346	)		(697	)
Loans receivable originated and purchased, held for sale		(31,699	)		(20,877	)
Proceeds from sale of loans receivable, held for sale		31,904			24,879
Changes in assets and liabilities
Increase in accounts receivable and unbilled revenues, net		(28,147	)		(21,730	)
Increase in fuel oil stock		(35,904	)		(10,520	)
Decrease in federal tax deposit		—			30,000
Increase (decrease) in accounts payable		54,232			(5,204	)
Increase in taxes accrued		18,744			11,406
Changes in other assets and liabilities		2,955			4,524

Net cash provided by operating activities		169,978			203,382

Cash flows from investing activities
Available-for-sale investment and mortgage-related securities purchased		(224,096	)		(175,000	)
Principal repayments on available-for-sale investment and mortgage-related securities		443,493			381,960
Proceeds from sale of available-for-sale mortgage-related securities		—			61,131
Net increase in loans held for investment		(240,078	)		(196,795	)
Net proceeds from sale of investments		8,879			—
Capital expenditures		(139,122	)		(146,982	)
Contributions in aid of construction		13,112			13,227
Other		5,721			2,043

Net cash used in investing activities		(132,091	)		(60,416	)

Cash flows from financing activities
Net decrease in deposit liabilities		(188,342	)		(17,295	)
Net increase (decrease) in short-term borrowings with original maturities of three months or less		(75,175	)		53,153
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		50,814			45,577
Proceeds from other bank borrowings		904,532			1,050,907
Repayments of other bank borrowings		(791,335	)		(1,206,828	)
Proceeds from issuance of long-term debt		230,421			100,000
Repayment of long-term debt		(136,000	)		(110,000	)
Excess tax benefits from share-based payment arrangements		346			697
Net proceeds from issuance of common stock		15,449			3,392
Common stock dividends		(60,938	)		(75,469	)
Decrease in cash overdraft		(12,076	)		(4,239	)
Other		(6,855	)		(6,714	)

Net cash used in financing activities		(69,159	)		(167,519	)

Cash flows from discontinued operations-net cash provided by operating activities		—			7,190

Net decrease in cash and equivalents and federal funds sold		(31,272	)		(17,363	)
Cash and equivalents and federal funds sold, beginning of period		257,301			208,947

Cash and equivalents and federal funds sold, end of period	$	226,029		$	191,584

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, 2006 and the unaudited consolidated financial statements and the notes thereto in HEI’s Quarterly Reports on SEC Form 10-Q for the quarters ended March 31, 2007 and June 30, 2007.

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, 2007 and December 31, 2006 and the results of its operations for the three and nine months ended September 30, 2007 and 2006 and its cash flows for the nine months ended September 30, 2007 and 2006. 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, 2007
Revenues from external customers	$	567,570	$	105,507	$	384		$	673,461
Intersegment revenues (eliminations)		45		—		(45	)		—

Revenues		567,615		105,507		339			673,461

Profit (loss)*		19,686		18,525		(8,265	)		29,946
Income taxes (benefit)		6,811		6,794		(3,540	)		10,065

Net income (loss)		12,875		11,731		(4,725	)		19,881

Nine months ended September 30, 2007
Revenues from external customers		1,507,829		317,493		2,925		$	1,828,247
Intersegment revenues (eliminations)		176		—		(176	)		—

Revenues		1,508,005		317,493		2,749			1,828,247

Profit (loss)*		36,994		56,670		(26,989	)		66,675
Income taxes (benefit)		13,016		20,761		(11,296	)		22,481

Net income (loss)		23,978		35,909		(15,693	)		44,194

Assets (at September 30, 2007)		3,224,130		6,792,413		14,056			10,030,599

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

Net income (loss)		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

Net income (loss)		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

*	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 16 through 41.

(4) Bank subsidiary

Selected financial information

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)	2007		2006		2007		2006
Interest and dividend income
Interest and fees on loans	$	61,817	$	59,417	$	182,191	$	171,893
Interest and dividends on investment and mortgage-related securities		26,497		28,368		85,090		89,315

		88,314		87,785		267,281		261,208

Interest expense
Interest on deposit liabilities		20,381		19,701		61,951		52,095
Interest on other borrowings		20,243		18,891		57,230		54,361

		40,624		38,592		119,181		106,456

Net interest income		47,690		49,193		148,100		154,752
Provision for loan losses		2,700		—		3,900		—

Net interest income after provision for loan losses		44,990		49,193		144,200		154,752

Noninterest income
Fees from other financial services		7,153		6,548		20,539		19,730
Fee income on deposit liabilities		6,583		4,653		19,095		13,218
Fee income on other financial products		1,977		1,739		5,845		6,308
Gain on sale of securities		—		1,735		—		1,735
Other income		1,480		878		4,733		3,699

		17,193		15,553		50,212		44,690

Noninterest expense
Compensation and employee benefits		16,173		17,398		52,733		52,711
Occupancy		5,418		4,942		15,707		13,895
Equipment		3,630		3,768		10,893		10,900
Services		6,385		5,600		22,638		13,441
Data processing		2,596		2,534		7,799		7,541
Other expense		9,456		9,926		27,972		27,202

		43,658		44,168		137,742		125,690

Income before income taxes		18,525		20,578		56,670		73,752
Income taxes		6,794		7,108		20,761		27,237

Net income	$	11,731	$	13,470	$	35,909	$	46,515

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

Consolidated Balance Sheet Data (unaudited)


(in thousands)	September 30, 2007			December 31, 2006
Assets
Cash and equivalents	$	156,721		$	172,370
Federal funds sold		59,009			79,671
Available-for-sale investment and mortgage-related securities		2,160,841			2,367,427
Investment in stock of Federal Home Loan Bank of Seattle, at cost		97,764			97,764
Loans receivable, net		4,020,112			3,780,461
Other		212,344			223,666
Goodwill and other intangibles, net		85,622			87,140

	$	6,792,413		$	6,808,499

Liabilities and stockholder’s equity
Deposit liabilities–noninterest-bearing	$	657,866		$	648,915
Deposit liabilities–interest-bearing		3,729,340			3,926,633
Other borrowings		1,731,799			1,568,585
Other		98,577			104,470

		6,217,582			6,248,603

Common stock		325,330			323,154
Retained earnings		282,243			280,046
Accumulated other comprehensive loss, net of tax benefits		(32,742	)		(43,304	)

		574,831			559,896

	$	6,792,413		$	6,808,499

Other borrowings consisted of securities sold under agreements to repurchase and advances from the Federal Home Loan Bank (FHLB) of Seattle of $901 million and $831 million, respectively, as of September 30, 2007 and $730 million and $839 million, respectively, as of December 31, 2006.

As of September 30, 2007, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.2 billion.

(5) Retirement benefits

For the first nine months of 2007, HECO contributed $8.2 million, ASB contributed $0.9 million and HEI contributed $0.1 million to their respective retirement benefit plans, compared to $7.4 million, $2.3 million and $0.1 million, respectively, in the first nine months of 2006. The Company’s current estimate of contributions to its retirement benefit plans in 2007 is $13.1 million (including $12.1 million by HECO, $0.9 million by ASB and $0.1 million by HEI), compared to contributions of $12.9 million in 2006. In addition, the Company expects to pay directly $1.7 million of benefits in 2007, compared to $1.2 million paid in 2006.

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)	2007			2006			2007			2006			2007			2006			2007			2006
Service cost	$	7,746		$	8,200		$	1,166		$	1,277		$	23,250		$	24,454		$	3,606		$	3,822
Interest cost		14,494			13,603			2,598			2,616			43,358			40,639			8,232			8,003
Expected return on plan assets		(17,091	)		(18,005	)		(2,619	)		(2,486	)		(51,291	)		(53,679	)		(7,321	)		(7,432	)
Amortization of unrecognized transition obligation		—			1			785			785			2			4			2,354			2,353
Amortization of prior service cost (gain)		(50	)		(29	)		3			3			(148	)		(256	)		10			10
Recognized actuarial loss		2,796			2,965			—			43			8,486			9,090			—			369

Net periodic benefit cost	$	7,895		$	6,735		$	1,933		$	2,238		$	23,657		$	20,252		$	6,881		$	7,125

The Company recorded retirement benefits expense of $25 million and $21 million in the first nine months of 2007 and 2006, respectively. The electric utilities charged a portion of the net periodic benefit costs to plant. Also, in

an interim order issued in April 2007, the amount of HELCO’s net periodic benefit costs to be recovered in rates was established. Thus, any costs determined under SFAS No. 87, as amended, that are over/under this amount subsequent to the interim order are charged/credited to a regulatory asset/liability. Further, under the interim order, a regulatory asset (representing HELCO’s $12.8 million prepaid pension asset as of December 31, 2006 prior to the adoption of SFAS No. 158) was allowed to be recovered (and is being amortized) over a period of five years. Retirement benefits expense for HELCO for the first nine months of 2007 was $3.5 million, but would have been $2.5 million if the pension and postretirement benefits other than pensions (OPEB) tracking mechanisms had not been adopted in the April 2007 interim order issued in HELCO’s 2006 test year rate case.

Also, see Note 4, “Retirement benefits,” and Note 5, “Commitments and contingencies—Interim increases,” of HECO’s “Notes to Consolidated Financial Statements” for a discussion of the PUC’s treatment of HECO’s prepaid pension asset and retirement benefits expenses in an interim D&O rendered in HECO’s 2007 test year rate case and in an amended proposed final D&O in HECO’s 2005 test year rate case, both rendered in October 2007.

ASB retirement benefit plan changes (subject to approval)

In October 2007, ASB informed its employees of its intent, subject to the approval of the HEI Board of Directors (Board), to adopt changes to its defined benefit pension plan effective December 31, 2007 and provide employer contributions to its retirement savings plan beginning January 1, 2008.

The changes to the plans would affect most employees and senior management and include:

Ending the accrual of benefits in ASB’s defined benefit pension plan for participants effective December 31, 2007. There would be no new participants to ASB’s defined benefit pension plan after that date.

Providing for a matching employer contribution under ASB’s retirement savings plan of 100% on the first 4% of eligible pay contributed by participants.

Providing for a discretionary employer contribution up to 6% of eligible pay to ASB’s retirement savings plan that would not be contingent on contributions by participants. The discretionary contribution would be based on the participant’s number of years of vested service.

The changes would not affect the vested pension benefits of former participants, including ASB retirees, as of December 31, 2007. All active participants who are employed on December 31, 2007 will become fully vested in their accrued pension benefit as of December 31, 2007.

Upon Board approval, both plan assets and obligations will be remeasured, and any curtailment gain or loss will be recognized. ASB anticipates a curtailment gain will be recorded, but no assurance can be given that the Board will approve the changes or that, if approved, the facts and actuarial assumptions at the time of approval will result in a gain.

(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 (4,799,822 shares available for issuance under outstanding and future grants and awards as of September 30, 2007) 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 new shares for NQSOs, restricted stock (nonvested 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 (i.e., cliff vesting) 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. NQSOs and SARs compensation expense has been recognized in accordance with the fair value-based measurement method of accounting. The estimated fair value of each NQSO and SAR grant was calculated on the date of grant using a Binomial Option Pricing Model.

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 measurement method of accounting. Dividends on restricted stock are paid quarterly in cash.

The Company’s share-based compensation expense and related income tax benefit (including a valuation allowance due to limits on the deductibility of executive compensation) are as follows:


($ in millions)	Three months ended September 30		Nine months ended September 30
($ in millions)	2007	2006	2007	2006
Share-based compensation expense ¹	0.4	0.4	1.1	1.3
Income tax benefit	0.1	0.1	0.3	0.6

¹	The Company has not capitalized any share-based compensation cost. The estimated forfeiture rate for SARs was 4.6% and the estimated forfeiture rate for restricted stock was 6.3%.

Nonqualified stock options

Information about HEI’s NQSOs is summarized as follows:


September 30, 2007			Outstanding & Exercisable
Year of grant	Range of exercise prices		Number of options	Weighted- average remaining contractual life	Weighted- average exercise price
1998	$	20.50	6,000	0.5	$	20.50
1999		17.61 –17.63	48,300	1.8		17.62
2000		14.74	52,000	2.6		14.74
2001		17.96	83,000	3.6		17.96
2002		21.68	134,000	4.4		21.68
2003		20.49	280,500	5.5		20.49

	$	14.74 –21.68	603,800	4.4	$	19.68

As of December 31, 2006, NQSOs outstanding totaled 660,000, with a weighted-average exercise price of $19.68. As of September 30, 2007, all NQSOs outstanding were exercisable and had an aggregate intrinsic value (including dividend equivalents) of $3.3 million.

NQSO activity and statistics are summarized as follows:


($ in thousands, except prices)	Three months ended September 30			Nine months ended September 30
($ in thousands, except prices)	2007	2006		2007		2006
Shares granted	—		—		—		—
Shares forfeited	—		—		—		—
Shares expired	—		—		—		—
Shares vested	—		1,000		79,000		198,500
Aggregate fair value of vested shares	—	$	4	$	350	$	916
Shares exercised	—		50,500		56,200		167,000
Weighted-average exercise price	—	$	18.04	$	19.70	$	20.32
Cash received from exercise	—	$	911	$	1,107	$	3,393
Intrinsic value of shares exercised ¹	—	$	758	$	575	$	1,931
Tax benefit realized for the deduction of exercises	—	$	295	$	224	$	751
Dividend equivalent shares distributed under Section 409A	—		52		21,892		43,265
Weighted-average Section 409A distribution price	—	$	27.72	$	26.15	$	26.27
Intrinsic value of shares distributed under Section 409A	—	$	1	$	572	$	1,137
Tax benefit realized for Section 409A distributions	—	$	1	$	223	$	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, 2007, all NQSOs were vested.

Stock appreciation rights

Information about HEI’s SARs is summarized as follows:


September 30, 2007			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	4.4	$	26.02	280,000	4.1	$	26.02
2005		26.18	532,000	5.7		26.18	166,000	1.7		26.18

	$	26.02 – 26.18	857,000	5.2	$	26.12	446,000	3.2	$	26.08

As of December 31, 2006, the shares underlying SARs outstanding totaled 879,000, with a weighted-average exercise price of $26.12. As of September 30, 2007, the SARs outstanding and the SARs exercisable (including dividend equivalents) had no intrinsic value.

SARs activity and statistics are summarized as follows:


	Three months ended September 30			Nine months ended September 30
($ in thousands, except prices)	2007	2006		2007		2006
Shares granted	—		—		—		—
Shares forfeited	18,000		—		18,000		—
Shares expired	—		—		—		—
Shares vested	—		4,000		51,000		317,750
Aggregate fair value of vested shares	—	$	24	$	269	$	1,773
Shares exercised	—		—		4,000		—
Weighted-average exercise price	—		—	$	26.18		—
Cash received from exercise	—		—		—		—
Intrinsic value of shares exercised¹	—		—	$	3		—
Tax benefit realized for the deduction of exercises	—		—	$	1		—
Dividend equivalent shares distributed under Section 409A	—		94		23,760		28,600
Weighted-average Section 409A distribution price	—	$	27.72	$	26.15	$	26.37
Intrinsic value of shares distributed under Section 409A	—	$	3	$	621	$	754
Tax benefit realized for Section 409A distributions	—	$	1	$	242	$	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 right.

As of September 30, 2007, there was $0.7 million of total unrecognized compensation cost related to SARs and that cost is expected to be recognized over a weighted average period of 1.5 years.

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, 2007 and 2006, a total of 45,652 and 71,865 dividend equivalent shares for NQSO and SAR grants were distributed to SOIP participants, respectively. 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 will be paid within 2¹/2 months after the end of the calendar year. Upon retirement, an SOIP participant may elect to take distributions of dividend equivalents subject to Section 409A at the time of retirement or at the end of the calendar year.

Restricted stock

As of December 31, 2006, restricted stock shares outstanding totaled 91,800, with a weighted-average grant date fair value of $25.68. As of September 30, 2007, restricted stock shares outstanding totaled 150,500, with a weighted-average grant date fair value of $25.82. 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 2007, 16,000 restricted stock shares vested, 1,000 restricted stock shares were forfeited, and 75,700 shares of restricted stock with a grant date fair value of $1.9 million were granted. During the third quarter of 2007, no restricted stock shares vested, 1,000 restricted stock shares were forfeited and 9,300 shares of restricted stock with a grant date fair value of $0.2 million were granted. During the first nine months of 2006, 60,800 shares of restricted stock with a grant date fair value of $1.6 million were granted, 10,000 shares of restricted stock with a grant date fair value of $0.2 million vested and no restricted stock shares 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 grant date fair value of $0.2 million vested (with a realized tax benefit for tax deductions of $0.1 million). The tax benefit realized for the tax deductions from restricted stock was $0.2 million for the first nine months of 2007 and not significant for the first nine months of 2006.

As of September 30, 2007, there was $2.7 million of total unrecognized compensation cost related to nonvested restricted stock. The cost is expected to be recognized over a weighted-average period of 3.3 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, 2007 and 2006, the Company paid interest (net of amounts capitalized and including bank interest) to non-affiliates amounting to $167 million and $144 million, respectively.

For the nine months ended September 30, 2007 and 2006, the Company paid income taxes amounting to $5 million and $30 million, respectively.

Supplemental disclosures of noncash activities

Noncash increases in common stock for director and officer compensatory plans of the Company were $2.0 million and $2.3 million for the nine months ended September 30, 2007 and 2006, respectively.

Under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP), common stock dividends reinvested by shareholders in HEI common stock in noncash transactions amounted to $15 million and nil for the nine months ended September 30, 2007 and 2006, respectively. From March 23, 2004 to March 5, 2007, HEI satisfied the requirements of the HEI DRIP and the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) by acquiring for cash its common shares through open market purchases rather than the issuance of additional shares. On March 6, 2007, it began satisfying those requirements by the issuance of additional shares.

(9) Recent accounting pronouncements and interpretations

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 what impact, if any, the adoption of SFAS No. 157 will have on the Company’s financial statements.

The fair value option for financial assets and financial liabilities

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, Including an amendment of FASB Statement No. 115.” SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value, which should improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 must be adopted by January 1, 2008. The Company plans to adopt SFAS No. 159 on January 1, 2008. Management has not yet determined what impact, if any, the adoption of SFAS No. 159 will have on the Company’s financial statements.

Income tax benefits of dividends on share-based payment awards

In June 2007, the FASB ratified the EITF consensus reached on EITF Issue No. 06-11, “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards.” The consensus applies to share-based payment arrangements in which the employee receives dividends on the award during the vesting period, the dividend payment results in a tax deduction, and the employer thereby realizes a tax benefit during the vesting period (e.g., restricted stock awards issued by the Company). Under SFAS No. 123R, dividends paid during the vesting period on share-based payments that are expected to vest are charged to retained earnings because the compensation cost already reflects the expected value of those dividends, which are included in the grant date fair value of the award, but dividends on awards that do not vest are recognized as additional compensation cost. The consensus requires the tax benefit received on dividends associated with share-based awards that are charged to retained earnings to be recorded in additional paid-in capital and included in the pool of excess tax benefits available to absorb potential future tax deficiencies on share-based payment awards. A tax benefit recognized from a dividend on an award that is subsequently forfeited or is no longer expected to vest (and that is therefore reclassified as additional compensation expense) would be reclassified to the income statement if sufficient excess tax benefits are available in the pool of excess tax benefits in additional paid-in capital on the date of the reclassification. The consensus is effective for the tax benefits of dividends declared in fiscal years beginning after December 15, 2007. The Company will adopt this consensus on January 1, 2008 and the adoption is not expected to have an impact on the Company’s financial statements.

(10) Income taxes

In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109,” which 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 an income tax position taken or expected to be taken in a tax return. The Company adopted FIN 48 in the first quarter of 2007. The impact to the Company was a reclassification of certain deferred tax liabilities to a liability for tax uncertainties and a charge of $0.2 million to retained earnings as of January 1, 2007 for the cumulative effect of adoption of FIN 48.

In general, prior to January 1, 2007, the Company (except for ASB) recorded known interest on income taxes in “Interest expense – other than bank” (in “Interest and other charges” in HECO’s consolidated statements of income) and ASB recorded known interest on income taxes in “Expenses - Bank” (in “Other expense” in ASB’s consolidated statements of income). Since the adoption of FIN 48, the electric utilities and ASB record all (potential and known) interest on income taxes in “Interest and other charges” and “Other expense,” respectively, but the Company records such amounts in “Interest expense – other than on deposit liabilities and other bank borrowings.” For the first nine months of 2006, interest accrued on income taxes was insignificant. For the first nine months of 2007, $0.9 million of interest on income taxes was reflected in “Interest expense – other than on deposit liabilities and bank borrowings.” The Company will record penalties, if any, in the respective segment’s expenses.

As of January 1, 2007, the total amount of accrued interest related to uncertain tax positions and recognized on the balance sheet was $2.0 million.

As of January 1, 2007, the total amount of unrecognized tax benefits was $11 million, and of this amount, $0.6 million, if recognized, would affect the Company’s effective tax rate. Management concluded that it is reasonably possible that the unrecognized tax benefits will significantly decrease within the next 12 months due to the resolution of issues under examination by the Internal Revenue Service. Management cannot estimate the range of the reasonably possible change.

Tax years 2003 to 2006 currently remain subject to examination by the Internal Revenue Service and Department of Taxation of the State of Hawaii. HEIII, which owns leveraged lease investments in other states, is also subject to examination by those state tax authorities for tax years 2003 to 2006.

The Company’s effective tax rate for the first nine months of 2007 was 34%, compared to an effective tax rate for the first nine months of 2006 of 37%. The lower effective tax rate was primarily due to domestic production activities deductions related to the generation of electricity and the impact of state tax credits (including the acceleration of the

state tax credits associated with the write-off of a portion of CT-4 and CT-5 costs) recognized against a smaller income tax expense base.

(11) Sale of shares in Hoku Scientific, Inc.

HEI Properties, Inc. (HEIPI) held shares of Hoku Scientific, Inc. (Hoku), a materials science company focused on clean energy technologies. Shares of Hoku began trading on the Nasdaq Stock Market on August 5, 2005 and since then HEIPI had classified its Hoku shares as trading securities, carried at fair value with changes in fair value recorded in earnings. HEIPI began selling Hoku stock in February 2006 when HEIPI’s lock-up agreement expired. In the first nine months of 2006, HEIPI recognized a $1.3 million loss (unrealized and realized, net of taxes) on its Hoku shares. As of December 31, 2006, HEIPI had carried its remaining investment in Hoku shares at $1.2 million. In January 2007, HEIPI sold its remaining Hoku shares for a net after-tax gain of $0.9 million.

(12) Credit agreement

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 either 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. The annual fee is 10 basis points on the undrawn commitment amount. The agreement contains provisions for revised pricing in the event of a ratings change. For example, a ratings downgrade of HEI’s Senior Debt Rating (e.g., from BBB/Baa2 to BBB-/Baa3 by S&P and Moody’s, respectively) would result in a commitment fee increase of 2.5 basis points and an interest rate increase of 10 basis points on any drawn amounts. On the other hand, a ratings upgrade (e.g., from BBB/Baa2 to BBB+/Baa1) would result in a commitment fee decrease of 2 basis points and an interest rate decrease of 10 basis points on any drawn amounts. The agreement does not contain clauses that would affect access to the lines by reason of a ratings downgrade, nor does it have a broad “material adverse change” clause. However, the agreement does contain customary conditions which must be met in order to draw on it, such as the accuracy of certain of its representations at the time of a draw and compliance with its covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HEI). In addition to customary defaults, HEI’s failure to maintain its financial ratio, as defined in the agreement, or meet other requirements will result in an event of default. For example, under the agreement, it is an event of default if HEI fails to maintain a nonconsolidated “Capitalization Ratio” (funded debt) of 50% or less (ratio of 26% as of September 30, 2007, as calculated under the agreement) and “Consolidated Net Worth” of $850 million (Net Worth of $1.3 billion as of September 30, 2007, as calculated under the agreement), if there is a “Change in Control” of HEI, if any event or condition occurs that results in any “Material Indebtedness” of HEI being subject to acceleration prior to its scheduled maturity, if any “Material Subsidiary Indebtedness” actually becomes due prior to its scheduled maturity, or if ASB fails to remain well capitalized and to maintain specified minimum capital ratios. HEI’s syndicated credit facility is maintained to support the issuance of commercial paper, but may also be drawn to make investments in and advances to its subsidiaries, and for the Company’s working capital and general corporate purposes. As of November 1, 2007, the $100 million credit facility remained undrawn.

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)


	Three months ended September 30						Nine months ended September 30
(in thousands, except for ratio of earnings to fixed charges)	2007			2006			2007			2006
Operating revenues	$	561,720		$	568,236		$	1,499,766		$	1,545,557

Operating expenses
Fuel oil		222,721			227,288			549,771			594,940
Purchased power		144,918			138,758			390,161			378,916
Other operation		54,113			46,612			154,949			136,565
Maintenance		28,594			23,653			85,799			63,087
Depreciation		34,273			32,539			102,812			97,614
Taxes, other than income taxes		51,389			51,985			138,839			142,726
Income taxes		4,976			14,665			15,974			38,909

		540,984			535,500			1,438,305			1,452,757

Operating income		20,736			32,736			61,461			92,800

Other income
Allowance for equity funds used during construction		1,336			1,838			3,770			4,974
Other, net		3,819			1,379			(1,330	)		2,809

		5,155			3,217			2,440			7,783

Income before interest and other charges		25,891			35,953			63,901			100,583

Interest and other charges
Interest on long-term debt		11,478			10,777			34,364			32,331
Amortization of net bond premium and expense		621			565			1,813			1,651
Other interest charges		1,075			1,285			4,090			5,424
Allowance for borrowed funds used during construction		(656	)		(838	)		(1,840	)		(2,259	)
Preferred stock dividends of subsidiaries		228			228			686			686

		12,746			12,017			39,113			37,833

Income before preferred stock dividends of HECO		13,145			23,936			24,788			62,750
Preferred stock dividends of HECO		270			270			810			810

Net income for common stock	$	12,875		$	23,666		$	23,978		$	61,940

Ratio of earnings to fixed charges (SEC method)								1.84			3.36

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

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)


(in thousands, except par value)	September 30, 2007			December 31, 2006
Assets
Utility plant, at cost
Land	$	38,297		$	35,242
Plant and equipment		4,091,436			4,002,929
Less accumulated depreciation		(1,636,002	)		(1,558,913	)
Plant acquisition adjustment, net		54			93
Construction in progress		124,699			95,619

Net utility plant		2,618,484			2,574,970

Current assets
Cash and equivalents		9,265			3,859
Customer accounts receivable, net		143,228			125,524
Accrued unbilled revenues, net		100,191			92,195
Other accounts receivable, net		8,792			4,423
Fuel oil stock, at average cost		100,216			64,312
Materials and supplies, at average cost		34,960			30,540
Other		10,621			9,695

Total current assets		407,273			330,548

Other long-term assets
Regulatory assets		142,675			112,349
Unamortized debt expense		15,915			13,722
Other		39,783			31,545

Total other long-term assets		198,373			157,616

	$	3,224,130		$	3,063,134

Capitalization and liabilities
Capitalization
Common stock, $6²/3 par value, authorized 50,000 shares; outstanding 12,806 shares	$	85,387		$	85,387
Premium on capital stock		299,214			299,214
Retained earnings		710,103			700,252
Accumulated other comprehensive loss, net of income tax benefits		(103,090	)		(126,650	)

Common stock equity		991,614			958,203
Cumulative preferred stock – not subject to mandatory redemption		34,293			34,293
Long-term debt, net		872,949			766,185

Total capitalization		1,898,856			1,758,681

Current liabilities
Short-term borrowings–nonaffiliates		29,625			113,107
Accounts payable		147,059			102,512
Interest and preferred dividends payable		16,970			10,645
Taxes accrued		164,221			152,182
Other		47,489			43,120

Total current liabilities		405,364			421,566

Deferred credits and other liabilities
Deferred income taxes		109,867			118,055
Regulatory liabilities		257,817			240,619
Unamortized tax credits		59,328			57,879
Other		206,495			189,606

Total deferred credits and other liabilities		633,507			606,159

Contributions in aid of construction		286,403			276,728

	$	3,224,130		$	3,063,134

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Changes in Stockholder’s Equity (unaudited)


(in thousands, except per share amounts)	Common stock			Premium on capital stock		Retained earnings			Accumulated other comprehensive loss			Total
(in thousands, except per share amounts)	Shares	Amount		Premium on capital stock		Retained earnings			Accumulated other comprehensive loss			Total
Balance, December 31, 2006	12,806	$	85,387	$	299,214	$	700,252		$	(126,650	)	$	958,203
Comprehensive income:
Net income	—		—		—		23,978			—			23,978
Defined benefit retirement plans—amortization of net loss, prior service cost and transition obligation included in net periodic benefit cost, net of taxes of $3,410	—		—		—		—			5,355			5,355

Comprehensive income	—		—		—		23,978			5,355			29,333

Adjustment to initially apply a PUC interim D&O related to defined benefit retirement plans, net of taxes of $11,595	—		—		—		—			18,205			18,205
Adjustment to initially apply FIN 48	—		—		—		(620	)		—			(620	)
Common stock dividends	—		—		—		(13,507	)		—			(13,507	)

Balance, September 30, 2007	12,806	$	85,387	$	299,214	$	710,103		$	(103,090	)	$	991,614

Balance, December 31, 2005	12,806	$	85,387	$	299,214	$	654,686		$	(28	)	$	1,039,259
Net income	—		—		—		61,940			—			61,940
Common stock dividends	—		—		—		(29,381	)		—			(29,381	)

Balance, September 30, 2006	12,806	$	85,387	$	299,214	$	687,245		$	(28	)	$	1,071,818

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	2007			2006
(in thousands)
Cash flows from operating activities
Income before preferred stock dividends of HECO	$	24,788		$	62,750
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities
Depreciation of property, plant and equipment		102,812			97,614
Other amortization		6,450			5,907
Writedown of utility plant		11,701			—
Deferred income taxes		(17,925	)		(7,851	)
Tax credits, net		1,944			2,990
Allowance for equity funds used during construction		(3,770	)		(4,974	)
Changes in assets and liabilities
Increase in accounts receivable		(22,073	)		(7,189	)
Increase in accrued unbilled revenues		(7,996	)		(7,368	)
Increase in fuel oil stock		(35,904	)		(10,520	)
Increase in materials and supplies		(4,420	)		(3,323	)
Decrease in prepaid pension benefit cost		—			15,026
Increase in regulatory assets		(2,129	)		(2,296	)
Increase (decrease) in accounts payable		44,547			(14,853	)
Increase in taxes accrued		12,039			30,313
Changes in other assets and liabilities		17,515			(2,719	)

Net cash provided by operating activities		127,579			153,507

Cash flows from investing activities
Capital expenditures		(135,090	)		(137,345	)
Contributions in aid of construction		13,112			13,227
Other		5,259			407

Net cash used in investing activities		(116,719	)		(123,711	)

Cash flows from financing activities
Common stock dividends		(13,507	)		(29,381	)
Preferred stock dividends		(810	)		(810	)
Proceeds from issuance of long-term debt		230,421			—
Repayment of long-term debt		(126,000	)		—
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		(83,482	)		8,915
Decrease in cash overdraft		(12,076	)		(4,245	)

Net cash used in financing activities		(5,454	)		(25,521	)

Net increase in cash and equivalents		5,406			4,275
Cash and equivalents, beginning of period		3,859			143

Cash and equivalents, end of period	$	9,265		$	4,418

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, 2006 and the unaudited consolidated financial statements and the notes thereto in HECO’s Quarterly Reports on SEC Form 10-Q for the quarters ended March 31, 2007 and June 30, 2007.

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, 2007 and December 31, 2006 and the results of their operations for the three and nine months ended September 30, 2007 and 2006 and their cash flows for the nine months ended September 30, 2007 and 2006. 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 Hawaii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (MECO) 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, HELCO and MECO under an expense agreement and HECO’s obligations under its trust guarantee and its guarantee of the obligations of HELCO and MECO 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, 2007 and December 31, 2006 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, 2007 and 2006 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, 2007, HECO and its subsidiaries had six 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, 2007 totaled $390 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $106 million, $136 million, $51 million and $25 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 variable interest entity (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 reviewed its significant PPAs and determined in 2004 that the IPPs at that time 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 after 2004 its efforts to obtain from the IPPs the information necessary to make the determinations required under FIN 46R. In January 2005, 2006 and 2007, 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 necessary information, except that Kalaeloa provided the information pursuant to the amendments to the PPA (see below) and Kaheawa Wind Power, LLC (KWP) provided information as required under the PPA. Management has concluded that MECO does not have to consolidate KWP (which began selling power to MECO in June 2006 from its 30 MW windfarm) as MECO does not have a variable interest in KWP because the PPA does not require MECO to absorb variability of KWP.

If the requested information is ultimately received from the other IPPs, a possible outcome of future analysis is the consolidation of one or more of such IPPs 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. If HECO and its subsidiaries determine they are required to consolidate the financial statements of such an IPP and the consolidation has a material effect, HECO and its subsidiaries would retrospectively apply FIN 46R in accordance with SFAS No. 154, “Accounting Changes and Error Corrections.”

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.

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 affecting 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 ECAC to the extent the fuel and fuel-related energy payments are not included in base energy rates.

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. In December 2005, Apollo assigned the PPA to a subsidiary, which voluntarily, unilaterally and irrevocably waived and relinquished its right and benefit under the PPA to collect the floor rate for the entire term of the PPA. The 20.5 MW facility began commercial operations in April 2007. Based on information available, management concluded that HELCO does not have to consolidate Apollo as HELCO does not have a variable interest in Apollo because the PPA does not require HELCO to absorb any variability of Apollo.

(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, 2007 and 2006, HECO and its subsidiaries included approximately $134 million and $137 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

(4) Retirement benefits

For the first nine months of 2007, HECO and its subsidiaries contributed $8.2 million to their retirement benefit plans, compared to $7.4 million in the first nine months of 2006. HECO and its subsidiaries’ current estimate of contributions to their retirement benefit plans in 2007 is $12.1 million, compared to contributions of $9.8 million in 2006. In addition, HECO and its subsidiaries expect to pay directly $0.5 million of benefits in 2007, compared to $0.6 million paid in 2006.

The components of net periodic benefit cost were as follows:


(in thousands)	Three months ended September 30												Nine months ended September 30
	Pension benefits						Other benefits						Pension benefits						Other benefits
	2007			2006			2007			2006			2007			2006			2007			2006
Service cost	$	6,418		$	6,749		$	1,137		$	1,244		$	19,109		$	19,970		$	3,516		$	3,721
Interest cost		12,951			12,111			2,515			2,547			38,637			36,237			7,998			7,790
Expected return on plan assets		(15,311	)		(16,208	)		(2,580	)		(2,445	)		(45,789	)		(48,257	)		(7,201	)		(7,312	)
Amortization of unrecognized transition obligation		—			1			783			782			1			2			2,348			2,347
Amortization of prior service gain		(191	)		(193	)		—			—			(572	)		(578	)		—			—
Recognized actuarial loss		2,625			2,655			—			39			7,861			8,043			—			349

Net periodic benefit cost	$	6,492		$	5,115		$	1,855		$	2,167		$	19,247		$	15,417		$	6,661		$	6,895

HECO and its subsidiaries recorded retirement benefits expense of $20 million and $16 million in the first nine months of 2007 and 2006, respectively. The electric utilities charged a portion of the net periodic benefit costs to plant. Also, in its interim decisions for HELCO’s 2006 test year rate case and HECO’s 2007 test year rate case (discussed below), the PUC approved the adoption of pension tracking mechanisms on an interim basis. The mechanisms are intended to smooth the impact to ratepayers of potential fluctuations in pension costs. In the interim decisions, the amount of HELCO’s and HECO’s net periodic benefit costs to be recovered in rates was established. Thus, any HELCO or HECO costs determined under SFAS No. 87, as amended, that are over/under those amounts subsequent to the interim orders, are charged/credited to a regulatory asset/liability. Under HELCO’s interim order, a regulatory asset (representing HELCO’s $12.8 million prepaid pension asset as of December 31, 2006 prior to the adoption of SFAS No. 158) was allowed to be recovered (and is being amortized) over a period of five years.

The HELCO pension tracking mechanism generally requires HELCO to make contributions to the pension trust in the amount of the actuarially calculated net periodic pension cost that would be allowed without penalty by the tax laws. A similar tracking mechanism for OPEB was also approved on an interim basis. As a result of these approvals, which are subject to the PUC’s final decision and order (D&O), HELCO reclassified, beginning April 5, 2007, to a regulatory asset the $18 million charge for retirement benefits that would otherwise be recorded in accumulated other comprehensive income pursuant to SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (which amount includes the prepaid pension asset, net of taxes, as well as other pension and OPEB charges related to SFAS No. 158). Retirement benefits expense for HELCO for the first nine months of 2007 was $3.5 million, but would have been $2.5 million if the pension and OPEB tracking mechanisms had not been adopted.

The HECO pension tracking mechanism, which will be effective in the fourth quarter of 2007 pursuant to the interim decision in HECO’s 2007 test year rate case, will allow HECO to recognize its actuarially calculated net periodic pension costs for ratemaking purposes. HECO is required to fund only the minimum level required under the law until the existing pension asset is reduced to zero, at which time HECO would make contributions to the pension trust in the amount of the actuarially calculated net periodic pension costs, except when limited by the ERISA minimum contribution requirements or the maximum contribution limitation on deductible contributions imposed by the Internal Revenue code. The issue of whether to amortize the pension asset (accumulated contributions to its pension fund in excess of accumulated net periodic pension cost (NPPC)), if any, is deferred until HECO’s next rate case proceeding. The pension tracking mechanism requires HECO to create a regulatory asset or regulatory liability, as appropriate, for the difference between the amount of the NPPC included in rates and the actual NPPC recorded. A similar tracking mechanism for OPEB was approved on an interim basis. The tracking mechanisms allow the

reclassification to a regulatory asset of the charge for retirement benefits that would otherwise be recorded in accumulated other comprehensive income.

(5) Commitments and contingencies

Interim increases

On September 27, 2005, the PUC issued an interim D&O in HECO’s 2005 test year rate case granting a general rate increase on Oahu of 4.36%, or $53.3 million (3.33%, or a net increase of $41.1 million excluding the transfer of certain costs from a surcharge line item on electric bills into base electricity charges), which was implemented on September 28, 2005.

On October 25, 2007, the PUC issued an amended proposed final D&O, authorizing an increase of 3.74%, or $45.7 million (or a net increase of $34 million or 2.7%), in annual revenues, based on a 10.7% return on average common equity (and an 8.66% return on rate base of $1.060 billion). The amended proposed final D&O, if issued in final form, would reverse the portion of the interim D&O related to the inclusion of HECO’s approximately $50 million pension asset, net of deferred income taxes, in rate base, and would require a refund of the $15 million of revenues associated with that reversal, including interest, retroactive to September 28, 2005 (the date the interim increase became effective). In the third quarter of 2007, HECO accrued $15 million for the potential customer refunds, reducing third quarter 2007 net income by $8.3 million. The potential additional refund to customers for the amounts recorded under interim rates in excess of the amount in the amended proposed final D&O from October 1, 2007 through October 21, 2007 with interest, is approximately $0.5 million.

Under state law, if one or more of the Commissioners were not present at the evidentiary hearings in the proceeding, and the decision is adverse to a party in the proceeding, a proposed final D&O is required before a final D&O can be issued. The parties adversely affected by the proposed final D&O have ten days to file exceptions and present arguments to the PUC, before a final D&O is rendered. HECO will not be filing exceptions or seeking to present arguments with respect to the amended proposed final D&O.

On April 4, 2007, the PUC issued an interim D&O in HELCO’s 2006 test year rate case granting a general rate increase on the island of Hawaii of 7.58%, or $24.6 million, which was implemented on April 5, 2007.

Through September 30, 2007, HECO and its subsidiaries had recognized $116 million of revenues with respect to interim orders ($14 million related to interim orders regarding certain integrated resource planning costs and $102 million related to interim orders, net of the $15 million accrual to reflect the PUC’s proposed final D&O in the 2005 HECO rate case, with respect to HECO’s and HELCO’s general rate increase requests based on a 2005 and a 2006 test year, respectively, and HECO’s interim surcharge to recover DG fuel and fuel trucking costs), which revenues are subject to refund, with interest, if and to the extent they exceed the amounts allowed in final D&Os.

On October 22, 2007, the PUC issued, and HECO implemented, an interim D&O granting HECO an increase of $69.997 million in annual revenues over current effective rates at the time of the interim decision, subject to refund, with interest. The interim increase is consistent with a settlement agreement (executed and filed on September 6, 2007 by HECO, the Consumer Advocate and the federal Department of Defense).

Energy cost adjustment clauses

On June 19, 2006, the PUC issued an order in HECO’s 2005 test year rate case indicating that the record in the pending case has not been developed for the purpose of addressing the factors in Act 162, signed into law by the Governor of Hawaii on June 2, 2006. Act 162 states that any automatic fuel rate adjustment clause requested by a public utility in an application filed with the PUC shall be designed, as determined in the PUC’s discretion, to (1) fairly share the risk of fuel cost changes between the public utility and its customers, (2) provide the public utility with sufficient incentive to reasonably manage or lower its fuel costs and encourage greater use of renewable energy, (3) allow the public utility to mitigate the risk of sudden or frequent fuel cost changes that cannot otherwise reasonably be mitigated through other commercially available means, such as through fuel hedging contracts, (4) preserve, to the extent reasonably possible, the public utility’s financial integrity, and (5) minimize, to the extent reasonably possible, the public utility’s need to apply for frequent applications for general rate increases to account for the changes to its fuel costs. While the PUC already reviewed the automatic fuel rate adjustment clause in rate cases, Act 162 required 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 ECAC that are raised by Act 162. The parties in the rate case proceeding are HECO, the Division of Consumer Advocacy, Department of Commerce and Consumer Affairs of the State of Hawaii (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. In October 2007, the PUC issued an amended proposed final D&O in HECO’s 2005 test year rate case in which the PUC stated it would not require the parties to file a stipulated procedural schedule on this issue, but that it expects HECO and HELCO to develop information relating to the Act 162 factors for examination during their next rate case proceedings.

The ECAC provisions of Act 162 were reviewed in the HELCO rate case based on a 2006 test year and are being reviewed in the HECO and MECO rate cases based on 2007 test years. In the HELCO 2006 test year rate case, the filed testimony of the Consumer Advocate’s consultant concluded that HELCO’s ECAC provides a fair sharing of the risks of fuel cost changes between HELCO and its ratepayers in a manner that preserves the financial integrity of HELCO without the need for frequent rate filings. On April 4, 2007 the PUC issued an interim D&O in the HELCO 2006 test year rate case which reflected the continuation of HELCO’s ECAC, consistent with a settlement agreement reached between HELCO and the Consumer Advocate.

In an order issued on August 24, 2007, the PUC added as an issue to be addressed in HECO’s 2007 test year rate case whether HECO’s ECAC complies with the requirements of Hawaii Revised Statutes §269-16(g). On September 6, 2007, HECO, the Consumer Advocate and the DOD (the parties) executed and filed an agreement on most of the issues in HECO’s 2007 test year rate case proceeding. The agreement is subject to approval by the PUC, which may accept or reject the agreement in part or in full. If the PUC does not accept the material terms of the agreement, any (and all) of the parties may withdraw from the agreement and pursue their respective positions in the proceeding without prejudice. In the settlement agreement, the parties agreed that the ECAC should continue in its present form for purposes of an interim rate increase and stated that they are continuing discussions with respect to the final design of the ECAC to be proposed for approval in the final D&O in this proceeding. On October 22, 2007 the PUC issued an interim D&O in HECO’s 2007 test year rate case which reflected the continuation of HECO’s ECAC for purposes of the interim increase, consistent with the agreement reached among the parties. The parties will file proposed findings of fact and conclusions of law on all issues in this proceeding, including the ECAC, and the schedule for that filing is being determined. The parties have agreed that their resolution of the ECAC issue will not affect their agreement regarding revenue requirements in the proceeding.

Management cannot predict the ultimate effect of the required Act 162 analysis on the continuation of the electric utilities’ existing ECACs.

On April 23, 2007, the PUC issued an order denying HECO’s proposal to recover DG fuel and trucking and low sulfur fuel oil (LFSO) trucking costs since January 1, 2006 through the reconciliation process for the ECAC. However, the PUC allowed HECO to establish and implement a new and separate interim surcharge to recover its additional DG and LFSO costs on a going forward basis. HECO implemented an interim surcharge to recover such costs incurred from May 1, 2007.

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 various proceedings, CT-4 and CT-5 became operational in mid-2004, there are no pending lawsuits involving the project, and work on ST-7 is proceeding. Noise mitigation equipment has been installed on CT-4 and CT-5 and additional noise mitigation work is ongoing 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. Construction of a noise barrier is scheduled for completion by the end of 2007, which should allow the units to operate full time.

Settlement Agreement; ST-7 costs incurred. 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). 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 adding a Hot Line service). While certain of these actions have been completed, and required payments to other parties to the settlement agreement were timely made, a number of these actions are ongoing.

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 anticipates an in-service date for ST-7 in mid-2009. HELCO has commenced engineering, design and certain construction work for ST-7. HELCO has made about $31 million in commitments for materials, equipment and outside services, a substantial portion of which are subject to cancellation charges. HELCO’s current cost estimate for ST-7 is approximately $92 million, of which approximately $7 million has been incurred through September 30, 2007.

CT-4 and CT-5 costs incurred. 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. 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, 2005 and 2006, respectively, and HELCO sought recovery of these costs as part of its 2006 test year rate case.

In March 2007, HELCO and the Consumer Advocate reached a settlement of the issues in the HELCO 2006 rate case proceeding, subject to PUC approval. Under the settlement, HELCO agreed to write-off approximately $12 million of plant-in-service costs, net of average accumulated depreciation, relating to CT-4 and CT-5, resulting in an after-tax charge to net income in the first quarter of 2007 of approximately $7 million (included in “Other, net” under “Other income (loss)” on HECO’s consolidated statement of income).

In April 2007, the PUC issued an interim D&O granting HELCO a 7.58% increase in rates, which reflects the settlement agreement reached between HELCO and the Consumer Advocate, including the agreement to write-off a portion of CT-4 and CT-5 costs. However, the interim order does not commit the PUC to accept any of the amounts in the interim increase in its final order. If it becomes probable that the PUC, in its final order, will disallow additional costs incurred for CT-4 and CT-5 for ratemaking purposes, HELCO will be required to record an additional write-off.

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. In total, this additional transmission capacity would benefit an area that comprises approximately 56% of the power demand on Oahu. 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 continued to believe that the proposed reliability project (the East Oahu Transmission Project) was needed and, in December 2003, filed an application with the PUC requesting approval to commit funds (currently estimated at $69.6 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 was completed and the PUC issued a Finding of No Significant Impact in April 2005.

In written testimony filed in June 2005, the consultant for the 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 prior to the denial in 2002 of the approval necessary for the partial underground/partial overhead 138 kV line, and the related allowance for funds used during construction (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. In October 2007, the PUC issued a final D&O approving HECO’s request to expend funds for a revised EOTP using a 46 kV system, but stating that the issue of recovery of the EOTP costs would be determined in a subsequent rate case.

Subject to obtaining 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 2010 and the completion date of the second phase is being evaluated.

As of September 30, 2007, the accumulated costs recorded for the EOTP amounted to $32 million, including (i) $12 million of planning and permitting costs incurred prior to 2003, (ii) $5 million of planning and permitting costs incurred after 2002 and (iii) $15 million for AFUDC. Management believes no adjustment to project costs is required as of September 30, 2007. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for ratemaking 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 to 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.

In 2001, management developed and expensed a preliminary estimate of HECO’s share of costs for continuing investigative work, remedial activities and monitoring at the Iwilei Unit of $1.1 million. 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 the DOH.

In 2003, HECO and other Participating Parties with active operations in the Iwilei area investigated their operations to evaluate whether their facilities were active sources of petroleum contamination in the area. HECO’s investigation concluded that its facilities were not then releasing petroleum. Routine maintenance and inspections of HECO facilities since then confirm that they are not currently releasing petroleum.

During 2006 and the beginning of 2007, the PRPs developed analyses of various remedial alternatives for two of the four remedial subunits of the Iwilei Unit. The DOH will use the analyses to make a final determination of which remedial alternatives the PRPs will be required to implement. The DOH is scheduled to complete the final remediation determinations for all remedial subunits of the Iwilei Unit by the end of 2007 or first quarter of 2008. HECO management developed an estimate of HECO’s share of the costs associated with implementing the PRP recommended remedial approaches for the two subunits covered by the analyses of $1.2 million, which was expensed in 2006. Subsequently, based on the estimated costs for the remaining two subunits, as well as updated estimates for total remediation costs, HECO management expensed an additional $0.6 million in the third quarter of 2007.

As of September 30, 2007, the accrual (amounts expensed less amounts expended) related to the Honolulu Harbor investigation was $1.9 million. Because (1) the full scope of additional investigative work, remedial activities

and monitoring remain to be determined, (2) the final cost allocation method among the PRPs has not yet been established 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.

Regional Haze Rule amendments. In June 2005, the EPA finalized amendments to the July 1999 Regional Haze Rule that require emission controls known as best available retrofit technology (BART) for industrial facilities emitting air pollutants that reduce visibility in National Parks by causing or contributing to regional haze. States must develop BART implementation plans and schedules in accordance with the amended regional haze rule by December 2007. After Hawaii adopts its plan, HECO, HELCO and MECO will evaluate the plan’s impacts, if any, on them. If any of the utilities’ generating units are ultimately required to install post-combustion control technologies to meet BART emission limits, the resulting capital and operation 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 rule, which established location and technology-based design, construction and capacity standards for existing cooling water intake structures. These standards applied to HECO’s Kahe, Waiau and Honolulu generating stations, unless the utility could demonstrate that at each facility implementation of these standards would result in costs either significantly higher than projected costs the EPA considered in establishing the standards for the facility (cost-cost test) or significantly greater than the benefits of meeting the standards (cost-benefit test). In either case, the EPA would then make a case-by-case determination of an appropriate performance standard. The regulation also would have allowed restoration of aquatic organism populations in lieu of meeting the standards. The rule required covered facilities to demonstrate compliance by March 2008. HECO had retained a consultant that was developing a cost effective compliance strategy and a preliminary assessment of technologies and operational measures under the rule.

On January 25, 2007, the U.S. Circuit Court for the Second Circuit issued a decision in Riverkeeper, Inc. v. EPA that remanded for further consideration and proceedings significant portions of the rule and found other portions of the rule to be impermissible. In particular, the court determined that restoration and the cost-benefit test were impermissible under the Clean Water Act. It also remanded the best technology available determination to permit the EPA to provide a reasoned explanation for its decision or a new determination. It remanded the cost-cost test for the EPA’s further consideration based on the best technology available determination and to afford adequate notice. The EPA is considering an appeal of the decision to the U.S. Supreme Court. If the decision stands, the Court of Appeals ruling reduces the compliance options available to HECO. In addition, the EPA has not issued a schedule for rulemaking, which would be necessary to comply with the court’s decision. On March 20, 2007, the EPA announced it had “suspended” the rule pending appeal or additional rulemaking. On July 9, 2007, the EPA formalized its determination to suspend the rule in a Federal Register notice. In the announcement, the EPA provided guidance to federal and state permit writers that they should use their “best professional judgment” in determining permit conditions regarding cooling water intake requirements at existing power plants. Currently, this guidance does not affect the HECO facilities subject to the cooling water intake requirements because none of the facilities are subject to permit renewal until mid-2009. Due to the uncertainties raised by the court’s decision as well as the need for further rulemaking by the EPA, management is unable to predict which compliance options, some of which could entail significant capital expenditures to implement, will be applicable to its facilities.

Collective bargaining agreements

As of September 30, 2007, 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 four-year collective bargaining and benefit agreements with the union covered a term from November 1, 2003 to October 31, 2007, but have been extended to November 7, 2007. The agreements provided 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). Negotiations for new agreements began in the third quarter of 2007 and are continuing.

(6) Cash flows

Supplemental disclosures of cash flow information

For the nine months ended September 30, 2007 and 2006, HECO and its subsidiaries paid interest (net of amounts capitalized) amounting to $33 million and $30 million, respectively.

For the nine months ended September 30, 2007 and 2006, HECO and its subsidiaries paid income taxes amounting to $6 million and $17 million, respectively.

Supplemental disclosure of noncash activities

The allowance for equity funds used during construction, which was charged to construction in progress as part of the cost of electric utility plant, amounted to $3.8 million and $5.0 million for the nine months ended September 30, 2007 and 2006, respectively.

(7) Recent accounting pronouncements and interpretations

For a discussion of recent accounting pronouncements and interpretations, see Note 9 of HEI’s “Notes to Consolidated Financial Statements.”

(8) Income taxes

The electric utilities record interest on income taxes in “Interest and other charges.” Interest accrued on income taxes was insignificant in the first nine months of 2006 and $0.5 million in the first nine months of 2007.

As of January 1, 2007, the total amount of accrued interest related to uncertain tax positions and recognized on the balance sheet was $0.6 million.

As of January 1, 2007, the total amount of unrecognized tax benefits was $4.7 million, and of this amount, $0.2 million, if recognized, would affect the electric utilities’ effective tax rate. Management concluded that it is reasonably possible that the unrecognized tax benefits will significantly decrease within the next 12 months due to the resolution of issues under examination by the Internal Revenue Service. Management cannot estimate the range of the reasonably possible change.

Tax years 2003 to 2006 currently remain subject to examination by the Internal Revenue Service and Department of Taxation of the State of Hawaii.

The electric utilities had an effective tax rate for the first nine months of 2007 of 34%, compared to 38% for the first nine months of 2006), primarily due to the domestic production activities deductions related to the generation of electricity and the impact of state tax credits (including the acceleration of the state tax credits associated with the write off of a portion of CT-4 and CT-5 costs) recognized against a smaller income tax expense base.

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


(in thousands)	Three months ended September 30						Nine months ended September 30
(in thousands)	2007			2006			2007			2006
Operating income from regulated and nonregulated activities before income taxes (per HEI consolidated statements of income)	$	31,366		$	48,651		$	73,147		$	134,077
Deduct:
Income taxes on regulated activities		(4,976	)		(14,665	)		(15,974	)		(38,909	)
Revenues from nonregulated activities		(5,895	)		(1,602	)		(8,239	)		(3,304	)
Add: Expenses from nonregulated activities		241			352			12,527			936

Operating income from regulated activities after income taxes (per HECO consolidated statements of income)	$	20,736		$	32,736		$	61,461		$	92,800

(10) 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. On March 14, 2007 the PUC issued a D&O approving HECO’s request to maintain the credit facility for five years (until March 31, 2011), to borrow under the credit facility with maturities in excess of 364 days, to use the proceeds from any borrowings with maturities in excess of 364 days to finance capital expenditures and/or to repay short-term or other borrowings used to finance or refinance capital expenditures and to use an expedited approval process to obtain PUC approval to increase the facility amount, renew the facility, refinance the facility or change other terms of the facility if such changes are required or desirable.

Any draws on the facility bear interest, at the option of HECO, at either 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. The annual fee is 8 basis points on the undrawn commitment amount. The agreement contains provisions for revised pricing in the event of a ratings change. For example, a ratings downgrade of HECO’s Senior Debt Rating (e.g., from BBB+/Baa1 to BBB/Baa2 by S&P and Moody’s, respectively) would result in a commitment fee increase of 2 basis points and an interest rate increase of 10 basis points on any drawn amounts. On the other hand, a ratings upgrade (e.g., from BBB+/Baa1 to A-/A3) would result in a commitment fee decrease of 1 basis point and an interest rate decrease of 10 basis points on any drawn amounts. The agreement does not contain clauses that would affect access to the lines by reason of a ratings downgrade, nor does it have a broad “material adverse change” clause. However, the agreement does contain customary conditions that must be met in order to draw on it, such as the accuracy of certain of its representations at the time of a draw and compliance with its covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HECO, and restricting HECO’s ability, as well as the ability of any of its subsidiaries, to guarantee indebtedness of the subsidiaries if such additional debt would cause the subsidiary’s “Consolidated Subsidiary Funded Debt to Capitalization Ratio” to exceed 65% (ratios of 47% for HELCO and 44% for MECO as of September 30, 2007, as calculated under the agreement)). In addition to customary defaults, HECO’s failure to maintain its financial ratios, as defined in its agreement, or meet other requirements will result in an event of default. For example, under the agreement, it is an event of default if HECO fails to maintain a “Consolidated Capitalization Ratio” (equity) of at least 35% (ratio of 54% as of September 30, 2007, as calculated under the agreement), if HECO fails to remain a wholly-owned subsidiary of HEI or if any event or condition occurs that results in any “Material Indebtedness” of HECO or any of its significant subsidiaries being subject to acceleration prior to its scheduled maturity. HECO’s syndicated credit facility is maintained to support the issuance of commercial paper, but it may also be drawn for general corporate purposes and capital expenditures. As of November 1, 2007, the $175 million credit facility remained undrawn.

On May 23, 2007, S&P lowered the long-term corporate credit and unsecured debt ratings on HECO, HELCO and MECO to BBB from BBB+ and stated that the downgrade “is the result of sustained weak bondholder protection parameters compounded by the financial pressure that continuous need for regulatory relief, driven by heightened capital expenditure requirements, is creating for the next few years.” The pricing for future borrowings under the line of credit facility did not change since the pricing level is “determined by the higher of the two” ratings by S&P and Moody’s, and Moody’s ratings did not change.

(11) Special Purpose Revenue Bonds (SPRBs)

On March 27, 2007, the Department of Budget and Finance of the State of Hawaii (the Department) issued (pursuant to a 2005 legislative authorization), at par, Series 2007A SPRBs in the aggregate principal amount of $140 million, with a maturity of March 1, 2037 and a fixed coupon interest rate of 4.65%, and loaned the proceeds to HECO ($100 million), HELCO ($20 million) and MECO ($20 million). Payment of the principal and interest on the SPRBs are insured by a surety bond issued by Financial Guaranty Insurance Company. Proceeds will be used to finance capital expenditures, including reimbursements to the electric utilities for previously incurred capital expenditures which, in turn, will be used primarily to repay short-term borrowings. As of September 30, 2007, approximately $35 million of proceeds from the Series 2007A SPRBs had not yet been drawn and were held by the construction fund trustee. HECO, HELCO and MECO’s long-term debt will increase from time to time as these remaining proceeds are drawn down.

On March 27, 2007, the Department issued, at par, Refunding Series 2007B SPRBs in the aggregate principal amount of $125 million, with a maturity of May 1, 2026 and a fixed coupon interest rate of 4.60%, and loaned the proceeds to HECO ($62 million), HELCO ($8 million) and MECO ($55 million). Proceeds from the sale were applied, together with other funds provided by the electric utilities, to the redemption at par on May 1, 2007 of the $75 million aggregate principal amount of 6.20% Series 1996A SPRBs (which had an original maturity of May 1, 2026) and to the redemption at a 2% premium on April 27, 2007 of the $50 million aggregate principal amount of 5⁷/8% Series 1996B SPRBs (which had an original maturity of December 1, 2026). Payment of the principal and interest on the refunding SPRBs are insured by a surety bond issued by Financial Guaranty Insurance Company.

(12) Sale of non-electric utility property

In August 2007, HECO sold land and a building that executives and management had been using as a recreational facility. The sale of the non-electric utility property resulted in an after-tax gain in the third quarter of 2007 of approximately $2.9 million (reflected in “Other, net” under “Other income” on HECO’s consolidated statement of income).

(13) 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. As of the dates and for the periods presented, there were no amounts for Uluwehiokama Biofuels Corp., a newly-formed, unregulated HECO subsidiary.

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 Statement of Income (unaudited)

Three months ended September 30, 2007


(in thousands)	HECO			HELCO		MECO		RHI		Reclassifications and eliminations		HECO consolidated
Operating revenues	$	369,937		97,294		94,489		—		—		$	561,720

Operating expenses
Fuel oil		157,568		17,983		47,170		—		—			222,721
Purchased power		97,025		38,143		9,750		—		—			144,918
Other operation		37,595		8,359		8,159		—		—			54,113
Maintenance		15,309		6,381		6,904		—		—			28,594
Depreciation		19,746		7,523		7,004		—		—			34,273
Taxes, other than income taxes		33,803		8,877		8,709		—		—			51,389
Income taxes		414		3,003		1,559		—		—			4,976

		361,460		90,269		89,255		—		—			540,984

Operating income		8,477		7,025		5,234		—		—			20,736

Other income
Allowance for equity funds used during construction		1,078		167		91		—		—			1,336
Equity in earnings of subsidiaries		7,545		—		—		—		(7,545	)		—
Other, net		4,196		175		34		(29	)	(557	)		3,819

		12,819		342		125		(29	)	(8,102	)		5,155

Income (loss) before interest and other charges		21,296		7,367		5,359		(29	)	(8,102	)		25,891

Interest and other charges
Interest on long-term debt		7,393		1,919		2,166		—		—			11,478
Amortization of net bond premium and expense		394		107		120		—		—			621
Other interest charges		891		670		71		—		(557	)		1,075
Allowance for borrowed funds used during construction		(527	)	(86	)	(43	)	—		—			(656	)
Preferred stock dividends of subsidiaries		—		—		—		—		228			228

		8,151		2,610		2,314		—		(329	)		12,746

Income (loss) before preferred stock dividends of HECO		13,145		4,757		3,045		(29	)	(7,773	)		13,145
Preferred stock dividends of HECO		270		133		95		—		(228	)		270

Net income (loss) for common stock	$	12,875		4,624		2,950		(29	)	(7,545	)	$	12,875

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Three months ended September 30, 2006


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

Nine months ended September 30, 2007


(in thousands)	HECO			HELCO		MECO		RHI		Reclassifications and eliminations		HECO consolidated
Operating revenues	$	978,279		262,747		258,740		—		—		$	1,499,766

Operating expenses
Fuel oil		368,405		53,688		127,678		—		—			549,771
Purchased power		267,744		98,625		23,792		—		—			390,161
Other operation		107,925		23,681		23,343		—		—			154,949
Maintenance		49,326		17,354		19,119		—		—			85,799
Depreciation		59,230		22,570		21,012		—		—			102,812
Taxes, other than income taxes		90,769		24,184		23,886		—		—			138,839
Income taxes		5,469		5,867		4,638		—		—			15,974

		948,868		245,969		243,468		—		—			1,438,305

Operating income		29,411		16,778		15,272		—		—			61,461

Other income
Allowance for equity funds used during construction		3,209		300		261		—		—			3,770
Equity in earnings of subsidiaries		10,372		—		—		—		(10,372	)		—
Other, net		6,931		(6,517	)	291		(58	)	(1,977	)		(1,330	)

		20,512		(6,217	)	552		(58	)	(12,349	)		2,440

Income (loss) before interest and other charges		49,923		10,561		15,824		(58	)	(12,349	)		63,901

Interest and other charges
Interest on long-term debt		21,842		5,691		6,831		—		—			34,364
Amortization of net bond premium and expense		1,142		312		359		—		—			1,813
Other interest charges		3,715		2,035		317		—		(1,977	)		4,090
Allowance for borrowed funds used during construction		(1,564	)	(151	)	(125	)	—		—			(1,840	)
Preferred stock dividends of subsidiaries		—		—		—		—		686			686

		25,135		7,887		7,382		—		(1,291	)		39,113

Income (loss) before preferred stock dividends of HECO		24,788		2,674		8,442		(58	)	(11,058	)		24,788
Preferred stock dividends of HECO		810		400		286		—		(686	)		810

Net income (loss) for common stock	$	23,978		2,274		8,156		(58	)	(10,372	)	$	23,978

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Nine months ended September 30, 2006


(in thousands)	HECO			HELCO		MECO		RHI		Reclassifications and eliminations		HECO consolidated
Operating revenues	$	1,034,483		254,275		256,799		—		—		$	1,545,557

Operating expenses
Fuel oil		397,360		62,860		134,720		—		—			594,940
Purchased power		268,019		91,479		19,418		—		—			378,916
Other operation		92,754		21,947		21,864		—		—			136,565
Maintenance		39,880		12,755		10,452		—		—			63,087
Depreciation		56,097		22,291		19,226		—		—			97,614
Taxes, other than income taxes		95,464		23,527		23,735		—		—			142,726
Income taxes		25,373		4,564		8,972		—		—			38,909

		974,947		239,423		238,387		—		—			1,452,757

Operating income		59,536		14,852		18,412		—		—			92,800

Other income
Allowance for equity funds used during construction		3,002		156		1,816		—		—			4,974
Equity in earnings of subsidiaries		21,408		—		—		—		(21,408	)		—
Other, net		3,789		239		978		(134	)	(2,063	)		2,809

		28,199		395		2,794		(134	)	(23,471	)		7,783

Income (loss) before interest and other charges		87,735		15,247		21,206		(134	)	(23,471	)		100,583

Interest and other charges
Interest on long-term debt		20,225		5,425		6,681		—		—			32,331
Amortization of net bond premium and expense		1,032		309		310		—		—			1,651
Other interest charges		5,072		1,832		583		—		(2,063	)		5,424
Allowance for borrowed funds used during construction		(1,344	)	(71	)	(844	)	—		—			(2,259	)
Preferred stock dividends of subsidiaries		—		—		—		—		686			686

		24,985		7,495		6,730		—		(1,377	)		37,833

Income (loss) before preferred stock dividends of HECO		62,750		7,752		14,476		(134	)	(22,094	)		62,750
Preferred stock dividends of HECO		810		400		286		—		(686	)		810

Net income (loss) for common stock	$	61,940		7,352		14,190		(134	)	(21,408	)	$	61,940

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

September 30, 2007


(in thousands)	HECO			HELCO		MECO		RHI	Reclassifications and eliminations		HECO consolidated
Assets
Utility plant, at cost
Land	$	28,969		4,982		4,346		—	—		$	38,297
Plant and equipment		2,490,617		817,229		783,590		—	—			4,091,436
Less accumulated depreciation		(992,110	)	(317,638	)	(326,254	)	—	—			(1,636,002	)
Plant acquisition adjustment, net		—		—		54		—	—			54
Construction in progress		91,490		23,213		9,996		—	—			124,699

Net utility plant		1,618,966		527,786		471,732		—	—			2,618,484

Investment in subsidiaries, at equity		393,669		—		—		—	(393,669	)		—

Current assets
Cash and equivalents		4,290		1,161		3,577		237	—			9,265
Advances to affiliates		36,100		—		7,000		—	(43,100	)		—
Customer accounts receivable, net		92,611		27,743		22,874		—	—			143,228
Accrued unbilled revenues, net		69,347		16,517		14,327		—	—			100,191
Other accounts receivable, net		6,385		2,150		2,939		—	(2,682	)		8,792
Fuel oil stock, at average cost		74,034		11,418		14,764		—	—			100,216
Materials and supplies, at average cost		16,169		5,323		13,468		—	—			34,960
Other		7,621		2,016		984		—	—			10,621

Total current assets		306,557		66,328		79,933		237	(45,782	)		407,273

Other long-term assets
Regulatory assets		83,079		43,793		15,803		—	—			142,675
Unamortized debt expense		10,751		2,490		2,674		—	—			15,915
Other		29,558		4,771		5,454		—	—			39,783

Total other long-term assets		123,388		51,054		23,931		—	—			198,373

	$	2,442,580		645,168		575,596		237	(439,451	)	$	3,224,130

Capitalization and liabilities
Capitalization
Common stock equity	$	991,614		195,831		197,631		207	(393,669	)	$	991,614
Cumulative preferred stock–not subject to mandatory redemption		22,293		7,000		5,000		—	—			34,293
Long-term debt, net		562,300		143,758		166,891		—	—			872,949

Total capitalization		1,576,207		346,589		369,522		207	(393,669	)		1,898,856

Current liabilities
Short-term borrowings–nonaffiliates		29,625		—		—		—	—			29,625
Short-term borrowings–affiliate		7,000		36,100		—		—	(43,100	)		—
Accounts payable		104,074		23,066		19,919		—	—			147,059
Interest and preferred dividends payable		11,068		3,180		2,914		—	(192	)		16,970
Taxes accrued		98,749		33,219		32,253		—	—			164,221
Other		33,203		7,910		8,836		30	(2,490	)		47,489

Total current liabilities		283,719		103,475		63,922		30	(45,782	)		405,364

Deferred credits and other liabilities
Deferred income taxes		82,194		19,233		8,440		—	—			109,867
Regulatory liabilities		177,012		45,997		34,808		—	—			257,817
Unamortized tax credits		32,817		13,181		13,330		—	—			59,328
Other		121,826		55,117		29,552		—	—			206,495

Total deferred credits and other liabilities		413,849		133,528		86,130		—	—			633,507

Contributions in aid of construction		168,805		61,576		56,022		—	—			286,403

	$	2,442,580		645,168		575,596		237	(439,451	)	$	3,224,130

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

December 31, 2006


(in thousands)	HECO			HELCO		MECO		RHI	Reclassifications and eliminations		HECO consolidated
Assets
Utility plant, at cost
Land	$	25,919		4,977		4,346		—	—		$	35,242
Plant and equipment		2,428,155		807,474		767,300		—	—			4,002,929
Less accumulated depreciation		(953,187	)	(298,590	)	(307,136	)	—	—			(1,558,913	)
Plant acquisition adjustment, net		—		—		93		—	—			93
Construction in progress		80,298		9,745		5,576		—	—			95,619

Net utility plant		1,581,185		523,606		470,179		—	—			2,574,970

Investment in subsidiaries, at equity		367,595		—		—		—	(367,595	)		—

Current assets
Cash and equivalents		2,328		738		518		275	—			3,859
Advances to affiliates		54,400		—		—		—	(54,400	)		—
Customer accounts receivable, net		81,912		24,228		19,384		—	—			125,524
Accrued unbilled revenues, net		64,235		14,437		13,523		—	—			92,195
Other accounts receivable, net		3,210		1,097		773		—	(657	)		4,423
Fuel oil stock, at average cost		40,680		9,761		13,871		—	—			64,312
Materials & supplies, at average cost		13,959		4,892		11,689		—	—			30,540
Other		7,537		1,463		695		—	—			9,695

Total current assets		268,261		56,616		60,453		275	(55,057	)		330,548

Other long-term assets
Regulatory assets		82,116		15,349		14,884		—	—			112,349
Unamortized debt expense		9,323		2,282		2,117		—	—			13,722
Other		23,507		4,340		3,698		—	—			31,545

Total other long-term assets		114,946		21,971		20,699		—	—			157,616

	$	2,331,987		602,193		551,331		275	(422,652	)	$	3,063,134

Capitalization and liabilities
Capitalization
Common stock equity	$	958,203		175,099		192,231		265	(367,595	)	$	958,203
Cumulative preferred stock–not subject to mandatory redemption		22,293		7,000		5,000		—	—			34,293
Long-term debt, net		481,240		131,046		153,899		—	—			766,185

Total capitalization		1,461,736		313,145		351,130		265	(367,595	)		1,758,681

Current liabilities
Short-term borrowings-nonaffiliates		113,107		—		—		—	—			113,107
Short-term borrowings-affiliate		—		49,400		5,000		—	(54,400	)		—
Accounts payable		61,672		22,572		18,268		—	—			102,512
Interest and preferred dividends payable		7,269		1,907		1,717		—	(248	)		10,645
Taxes accrued		96,846		26,981		28,355		—	—			152,182
Other		27,012		5,971		10,536		10	(409	)		43,120

Total current liabilities		305,906		106,831		63,876		10	(55,057	)		421,566

Deferred credits and other liabilities
Deferred income taxes		92,805		13,285		11,965		—	—			118,055
Regulatory liabilities		164,617		43,596		32,406		—	—			240,619
Unamortized tax credits		32,359		13,126		12,394		—	—			57,879
Other		110,473		52,274		26,859		—	—			189,606

Total deferred credits and other liabilities		400,254		122,281		83,624		—	—			606,159

Contributions in aid of construction		164,091		59,936		52,701		—	—			276,728

	$	2,331,987		602,193		551,331		275	(422,652	)	$	3,063,134

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Stockholder’s Equity (unaudited)

Nine months ended September 30, 2007


(in thousands)	HECO			HELCO		MECO		RHI		Reclassifications and eliminations		HECO consolidated
Balance, December 31, 2006	$	958,203		175,099		192,231		265		(367,595	)	$	958,203
Comprehensive income:
Net income		23,978		2,274		8,156		(58	)	(10,372	)		23,978
Defined benefit retirement plans - amortization of net loss, prior service cost and transition obligation included in net periodic benefit cost, net of taxes		5,355		285		671		—		(956	)		5,355

Comprehensive income (loss)		29,333		2,559		8,827		(58	)	(11,328	)		29,333

Adjustment to initially apply a PUC interim D&O related to defined benefit retirement plans, net of taxes		18,205		18,205		—		—		(18,205	)		18,205
Adjustment to initially apply FIN 48		(620	)	(32	)	(42	)	—		74			(620	)
Common stock dividends		(13,507	)	—		(3,385	)	—		3,385			(13,507	)

Balance, September 30, 2007	$	991,614		195,831		197,631		207		(393,669	)	$	991,614

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Stockholder’s Equity (unaudited)

Nine months ended September 30, 2006


(in thousands)	HECO			HELCO		MECO		RHI		Reclassifications and eliminations		HECO consolidated
Balance, December 31, 2005	$	1,039,259		189,407		194,190		118		(383,715	)	$	1,039,259
Issuance of common stock		—		—		—		300		(300	)		—
Net income		61,940		7,352		14,190		(134	)	(21,408	)		61,940
Common stock dividends		(29,381	)	(2,874	)	(6,522	)	—		9,396			(29,381	)

Balance, September 30, 2006	$	1,071,818		193,885		201,858		284		(396,027	)	$	1,071,818

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Nine months ended September 30, 2007


(in thousands)	HECO			HELCO		MECO		RHI		Reclassifications and eliminations		HECO consolidated
Cash flows from operating activities
Income (loss) before preferred stock dividends of HECO	$	24,788		2,674		8,442		(58	)	(11,058	)	$	24,788
Adjustments to reconcile income (loss) before preferred stock dividends of HECO to net cash provided by (used in) operating activities
Equity in (earnings) loss		(10,447	)	—		—		—		10,372			(75	)
Common stock dividends received from subsidiaries		3,460		—		—		—		(3,385	)		75
Depreciation of property, plant and equipment		59,230		22,570		21,012		—		—			102,812
Other amortization		2,722		872		2,856		—		—			6,450
Writedown of utility plant		—		11,701		—		—		—			11,701
Deferred income taxes		(9,627	)	(4,931	)	(3,367	)	—		—			(17,925	)
Tax credits, net		1,031		(184	)	1,097		—		—			1,944
Allowance for equity funds used during construction		(3,209	)	(300	)	(261	)	—		—			(3,770	)
Changes in assets and liabilities
Increase in accounts receivable		(13,874	)	(4,568	)	(5,656	)	—		2,025			(22,073	)
Increase in accrued unbilled revenues		(5,112	)	(2,080	)	(804	)	—		—			(7,996	)
Increase in fuel oil stock		(33,354	)	(1,657	)	(893	)	—		—			(35,904	)
Increase in materials and supplies		(2,210	)	(431	)	(1,779	)	—		—			(4,420	)
Decrease (increase) in regulatory assets		607		(533	)	(2,203	)	—		—			(2,129	)
Increase in accounts payable		42,402		494		1,651		—		—			44,547
Increase in taxes accrued		1,903		6,238		3,898		—		—			12,039
Changes in other assets and liabilities		12,999		6,766		(245	)	20		(2,025	)		17,515

Net cash provided by (used in) operating activities		71,309		36,631		23,748		(38	)	(4,071	)		127,579

Cash flows from investing activities
Capital expenditures		(79,725	)	(36,895	)	(18,470	)	—		—			(135,090	)
Contributions in aid of construction		7,388		3,480		2,244		—		—			13,112
Advances from (to) affiliates		18,300		—		(7,000	)	—		(11,300	)		—
Other		5,259											5,259

Net cash used in investing activities		(48,778	)	(33,415	)	(23,226	)	—		(11,300	)		(116,719	)

Cash flows from financing activities
Common stock dividends		(13,507	)	—		(3,385	)			3,385			(13,507	)
Preferred stock dividends		(810	)	(400	)	(286	)	—		686			(810	)
Proceeds from issuance of long-term debt		142,253		20,581		67,587		—		—			230,421
Repayment of long-term debt		(62,280	)	(8,020	)	(55,700	)	—		—			(126,000	)
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		(76,482	)	(13,300	)	(5,000	)	—		11,300			(83,482	)
Decrease in cash overdraft		(9,743	)	(1,654	)	(679	)	—		—			(12,076	)

Net cash provided by (used in) financing activities		(20,569	)	(2,793	)	2,537		—		15,371			(5,454	)

Net increase (decrease) in cash and equivalents		1,962		423		3,059		(38	)	—			5,406
Cash and equivalents, beginning of period		2,328		738		518		275		—			3,859

Cash and equivalents, end of period	$	4,290		1,161		3,577		237		—		$	9,265

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Nine months ended September 30, 2006


(in thousands)	HECO			HELCO		MECO		RHI		Reclassifications and eliminations		HECO consolidated
Cash flows from operating activities
Income (loss) before preferred stock dividends of HECO	$	62,750		7,752		14,476		(134	)	(22,094	)	$	62,750
Adjustments to reconcile income (loss) before preferred stock dividends of HECO to net cash provided by (used in) operating activities
Equity in earnings		(21,483	)	—		—		—		21,408			(75	)
Common stock dividends received from subsidiaries		9,471		—		—		—		(9,396	)		75
Depreciation of property, plant and equipment		56,097		22,291		19,226		—		—			97,614
Other amortization		3,032		409		2,466		—		—			5,907
Deferred income taxes		(4,929	)	(521	)	(2,401	)	—		—			(7,851	)
Tax credits, net		1,805		360		825		—		—			2,990
Allowance for equity funds used during construction		(3,002	)	(156	)	(1,816	)	—		—			(4,974	)
Changes in assets and liabilities
Increase in accounts receivable		(6,401	)	(668	)	(1,018	)	—		898			(7,189	)
Increase in accrued unbilled revenues		(4,536	)	(1,832	)	(1,000	)	—		—			(7,368	)
Increase in fuel oil stock		(4,309	)	(2,230	)	(3,981	)	—		—			(10,520	)
Increase in materials and supplies		(601	)	(973	)	(1,749	)	—		—			(3,323	)
Decrease in prepaid pension benefit cost		10,664		1,924		2,438		—		—			15,026
Decrease (increase) in regulatory assets		(218	)	32		(2,110	)	—		—			(2,296	)
Decrease in accounts payable		(12,605	)	(2,243	)	(5	)	—		—			(14,853	)
Increase in taxes accrued		20,606		5,225		4,482		—		—			30,313
Changes in other assets and liabilities		(5,941	)	5,624		(1,504	)	—		(898	)		(2,719	)

Net cash provided by (used in) operating activities		100,400		34,994		28,329		(134	)	(10,082	)		153,507

Cash flows from investing activities
Capital expenditures		(65,033	)	(29,032	)	(43,280	)	—		—			(137,345	)
Contributions in aid of construction		8,235		1,770		3,222		—		—			13,227
Advances from (to) affiliates		(11,950	)	—		5,250		—		6,700			—
Other		107		—		—		—		300			407

Net cash used in investing activities		(68,641	)	(27,262	)	(34,808	)	—		7,000			(123,711	)

Cash flows from financing activities
Common stock dividends		(29,381	)	(2,874	)	(6,522	)	—		9,396			(29,381	)
Preferred stock dividends		(810	)	(400	)	(286	)	—		686			(810	)
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		3,665		(2,800	)	14,750		—		(6,700	)		8,915
Increase (decrease) in cash overdraft		(3,295	)	(950	)	—		300		(300	)		(4,245	)

Net cash provided by (used in) financing activities		(29,821	)	(7,024	)	7,942		300		3,082			(25,521	)

Net increase in cash and equivalents		1,938		708		1,463		166		—			4,275
Cash and equivalents, beginning of period		8		3		4		128		—			143

Cash and equivalents, end of period	$	1,946		711		1,467		294		—		$	4,418

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

The following discussion updates “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in HEI’s and HECO’s 2006 Form 10-K and should be read in conjunction with the annual (as of and for the year ended December 31, 2006) and quarterly (as of and for the three months ended March 31, 2007, and as of and for the three and six months ended June 30, 2007) consolidated financial statements of HEI and HECO and accompanying notes.

HEI CONSOLIDATED

HEI, through HECO and its subsidiaries, Hawaii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (MECO), provide the only electric public utility service to approximately 95% of Hawaii’s population. HEI also provides a wide array of banking and other financial services to consumers and businesses through its bank subsidiary, ASB, Hawaii’s third largest financial institution based on assets as of December 31, 2006.

In the first nine months of 2007, net income was $44 million, or $0.54 per share, compared to $92 million, or $1.13 per share, in the first nine months of 2006. The significant decline was due to lower electric utility and bank earnings.

The utilities’ earnings were impacted by higher expenses, which were expected and are expected to continue as they maintain the reliability of aging generating units as well as add new plant and supporting infrastructure. The utilities’ earnings were also impacted by an $8 million after-tax accrual in the third quarter for a potential refund of a portion of HECO’s 2005 test year interim rate increase and a $7 million after-tax write-off of HELCO plant in the first quarter, but benefited from 0.5% higher kilowatthour (KWH) sales and interim rate relief at HELCO. Future improvement in utility earnings, however, is largely dependent on the amount and timing of further rate relief to cover the higher expenses.

ASB’s earnings were adversely affected by the challenging interest rate environment—a flat or inverted yield curve throughout 2006 and the first nine months of 2007—and higher legal and other litigation expenses and costs to strengthen ASB’s risk management and compliance infrastructure, which include increased staffing costs and are expected to continue. Although management works to increase select lines of business, to make appropriate adjustments as it assesses its asset/liability mix and to improve its efficiency ratio, ASB’s earnings are still largely dependent on the level of interest rates and the shape of the yield curve.

The Company’s operations (e.g. KWH sales, loans and deposits) are heavily influenced by Hawaii’s economy, which is driven by tourism, the federal government (including the military), real estate and construction. See “Economic conditions” below.

RESULTS OF OPERATIONS


(in thousands, except per share amounts)	Three months ended September 30				% change		Primary reason(s) for significant change*
(in thousands, except per share amounts)	2007		2006		% change		Primary reason(s) for significant change*
Revenues	$	673,461	$	673,894	—		Decreases for the electric utility and “other” segments, offset by increase for the bank segment

Operating income		48,017		66,356	(28	)	Decrease for the electric utility and the bank segments, slightly offset by a reduction in losses for the “other” segment

Net income		19,881		32,323	(38	)	Lower operating income and AFUDC and higher “interest expense—other than on deposit liabilities and other bank borrowings,” partly offset by lower income taxes resulting from lower income before taxes and a lower effective income tax rate **

Basic earnings per common share	$	0.24	$	0.40	(40	)	Lower net income

Weighted-average number of common shares outstanding		82,481		81,213	2		Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other Company plans

(in thousands, except per share amounts)	Nine months ended September 30				% change		Primary reason(s) for significant change*
(in thousands, except per share amounts)	2007		2006		% change		Primary reason(s) for significant change*
Revenues	$	1,828,247	$	1,853,825	(1	)	Decrease for the electric utility segment, slightly offset by increases for the bank and “other” segments

Operating income		121,867		196,236	(38	)	Decrease for the electric utility and the bank segments, slightly offset by a reduction in losses for the “other” segment

Net income		44,194		91,884	(52	)	Lower operating income and AFUDC and higher “interest expense—other than on deposit liabilities and other bank borrowings,” partly offset by lower income taxes resulting from lower income before taxes and a lower effective income tax rate **

Basic earnings per common share	$	0.54	$	1.13	(52	)	Lower net income

Weighted-average number of common shares outstanding		81,949		81,099	1		Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other Company plans

*	Also, see segment discussions which follow.

**	The Company’s effective tax rate for the first nine months of 2007 was 34%, compared to an effective tax rate for the first nine months of 2006 of 37% (see Note 10 in HEI’s “Notes to Consolidated Financial Statements”).

Dividends

On November 1, 2007, the HEI Board of Directors (Board) maintained the quarterly dividend of $0.31 per common share. The payout ratios for 2006 and the first nine months of 2007 were 93% and 172%, respectively. Historically-low net income for the first nine months of 2007 resulted in the high dividend payout ratio. Net income for the first nine months of 2007 was affected by a number of factors, including higher other operation and maintenance (O&M) expenses, an $8 million accrual (net of taxes) for a potential refund of interim rates and a $7 million (net of taxes) write-off of plant at the electric utilities and higher legal and consulting expenses at ASB (see “Results of

Operations” in the “Electric Utilities” and “Bank” sections below). HEI’s Board and management continue to believe that HEI should achieve a payout ratio of 65% or lower on a sustainable basis and that cash flows should support an increase before it considers increasing the common stock dividend above its current level.

Economic conditions

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

Because HEI’s core businesses provide local electric utility and banking services, HEI’s operating results are significantly influenced by the strength of Hawaii’s economy. The state’s economic growth, which is fueled by the two largest components of Hawaii’s economy – tourism and the federal government – was estimated at 3% for 2006 and is forecasted at 2.9% for 2007 by DBEDT.

According to the latest available data, Hawaii ranked sixth among the states in its receipt of federal government expenditures per capita. For the federal fiscal year ended September 30, 2005 (latest available data), total federal government expenditures in Hawaii, including military expenditures, were $12.7 billion or $9,974 per capita, increasing 4% and 3%, respectively, over fiscal year 2004. Military spending, which is 39% of federal expenditures in Hawaii, increased 5% in 2005 compared to 2004.

Tourism is a significant component of Hawaii’s economy. In 2006, visitor expenditures reached a record $12.4 billion, a 4% increase compared to 2005. 2006 visitor days reached a record 68 million, a 1.2% increase compared to 2005. State economists currently expect a decline of 1.1% in visitor days in 2007 due to the impacts of declines in the mainland housing and mortgage markets. Visitor days were down 1.9% for the first nine months of 2007 compared to the same period a year ago. Visitor expenditures, however, are expected to grow by 2.6% in 2007 and were up 0.6% for the first nine months of 2007 compared with the same period in 2006.

The real estate and construction industries in Hawaii also influence HEI’s core businesses. Although the number of Oahu home sales continues to slow, prices have remained stable. However, total sales of single-family homes for the first nine months of 2007 decreased 7.4% compared to the same period last year. The median home price on Oahu was $650,000 in September 2007 compared to $620,000 in September 2006.

Despite recent turmoil in the mainland housing and mortgage markets, Hawaii’s construction industry remains healthy. Although private building permits for the first nine months of 2007 decreased 0.2% compared with the same period last year, government construction has been strong with contracts awarded up 5.6% in the first half of 2007. In addition, the multi-billion dollar military housing privatization initiative has added strength to the industry.

Overall, the outlook for Hawaii’s economy remains positive. However, economic growth is affected by the rate of expansion in the mainland U.S. and Japan economies and the growth in military spending, and is vulnerable to uncertainties in the world’s geopolitical environment. The projected real gross domestic product (GDP) growth for the U.S. and Japan in 2007 is 2% and 2.5%, respectively.

Management also monitors (1) oil prices, because of their impact on the rates the utilities charge for electricity and the potential effect of increased prices of electricity on usage, and (2) interest rates, because of their potential impact on ASB’s earnings, HEI’s and HECO’s cost of capital, pension costs and HEI’s stock price. Continued global demand and a weaker dollar pushed oil prices higher throughout the third quarter of 2007. Crude oil traded at an average price of $74.61 per barrel during the third quarter of 2007, compared to an average price of $70.28 per barrel in 2006, and is expected to continue trading at a premium through the end of the year due to continued geopolitical instability and tight refining capacity.

Long-term interest rates began to rise in the second quarter of 2007 and also rose at the end of September 2007, which may signal concern for future inflation. The spread between the 10-year and 2-year Treasuries was 0.62% as of September 30, 2007, compared to spreads of 0.16% as of June 30, 2007, 0.07% as of March 31, 2007, and (0.10)% as of December 31, 2006.

Pension and other postretirement benefits

See Note 5 and Note 4 of HEI’s and HECO’s “Notes to Consolidated Financial Statements,” respectively, for information concerning retirement benefit plan contributions, net periodic benefit costs and expenses, the impacts of HELCO and HECO interim D&Os and ASB’s retirement benefit plan changes for 2008 (subject to approval). ASB’s proposed change for 2008 from a defined benefit to a defined contribution retirement plan is designed to reflect marketplace conditions and the competitive landscape within the banking industry and among other Hawaii banks. Retirement benefits expense and cash funding requirements could increase in future years depending on numerous factors, including the performance of the equity markets and changes in interest rates.

For the first nine months of 2007, the retirement benefit plan assets generated a total return (net of investment management fees) of 9.3%, resulting in earnings and realized and unrealized gains of $94 million, compared to an 8.5% annual expected return on plan assets assumption and a total net return of 13.5% for 2006. The market value of the retirement benefit plans’ assets as of September 30, 2007 was $1.1 billion.

In part, the Company benchmarks its discount rate assumption to the Moody’s Daily Long-Term Corporate Bond Aa Yield Average, which was 6.03% at September 30, 2007 compared to 5.72% at December 31, 2006. The discount rate used at December 31, 2006 was 6.00%. The Company intends to have a cash-flow matching bond analysis prepared as of December 31, 2007 and will adopt its discount rate assumption based on the results of the study. Based on the current interest rate environment, the Company projects the discount rate at December 31, 2007 will be between 6.0% and 6.5%.

Consolidated HEI’s, consolidated HECO’s and ASB’s net periodic pension and other postretirement benefits expenses, net of amounts capitalized and tax benefits, are estimated to be $20 million, $16 million and $2 million, respectively, for 2007, compared to $17 million, $13 million and $3 million, respectively, for 2006.

Subject to the approval of the HEI Board, ASB will end the accrual of benefits for participants in ASB’s defined benefit plan effective December 31, 2007. Upon Board approval, both plan assets and obligations will be remeasured and ASB anticipates that a curtailment gain will be recorded, but no assurances can be given that the Board will approve the changes or that, if approved, the facts and actuarial assumptions at the time of approval will result in a gain.

Based on the market value of the pension plans’ assets as of December 31, 2006, an 8.5% return on plan asset assumption, contributions of $13 million in 2007, a range of 6.0% to 6.5% for the discount rate at December 31, 2007, ending the accrual of benefits in ASB’s defined benefit pension plan for participants effective December 31, 2007 and providing employer contributions to ASB’s retirement savings plan beginning January 1, 2008, and no further changes in assumptions or pension plan provisions, consolidated HEI’s, consolidated HECO’s and ASB’s 2008 retirement benefit expenses, net of amounts capitalized and tax benefits, are estimated to be:

Retirement benefit expense, net of amounts capitalized and tax benefits


	Discount rate
($ in millions)	6.0%			6.5%
Consolidated HEI ^{1, 2}	$	17		$	16
Consolidated HECO ²		17			16
ASB ¹		(1	)		(1	)

ASB’s estimated net credit of $1 million is associated with its defined benefit pension and other postretirement benefits and does not include the 2008 employer contributions to its retirement savings plan that are estimated to increase retirement benefit expenses by $3 million, net of tax benefits.

²	Reflects the impact of interim decisions for HELCO’s 2006 test year rate case and HECO’s 2007 test year rate case.

The electric utilities’ retirement benefit expenses have been allowable expenses for ratemaking, and higher retirement benefit expenses, along with other factors, may affect the timing and amount of future electric rate increase requests.

Based on the same assumptions used to estimate 2008 retirement benefits expense above, consolidated HEI’s, consolidated HECO’s and ASB’s accumulated other comprehensive income (AOCI) balances, net of tax benefits, related to SFAS No. 158 at December 31, 2007 are estimated to be:

AOCI balance, net of tax benefits, related to SFAS No. 158


($ in millions)	Actual as of				Estimate as of December 31, 2007
	December 31, 2006		September 30, 2007		Estimate as of December 31, 2007
	Discount rate 6.0%		Discount rate 6.0%		Discount rate
	Discount rate 6.0%		Discount rate 6.0%		6.0%		6.5%
Consolidated HEI ^{1, 2}	$	140	$	116	$	18	$	10
Consolidated HECO ¹		127		103		13		7
ASB ²		8		7		—		—

¹	Reflects the impact of interim decisions for HELCO’s 2006 test year rate case (implemented on April 5, 2007) and HECO’s 2007 test year rate case (implemented on October 22, 2007), including the reclassification of AOCI balances to regulatory assets.

²	Reflects ASB’s defined benefit pension plan and its proposed curtailment effective December 31, 2007.

The Pension Protection Act of 2006. The Pension Protection Act of 2006 (the 2006 Act) was signed into law on August 17, 2006. The 2006 Act makes significant changes to a wide variety of rules that apply to employee benefit plans, including those dealing with minimum funding requirements of defined benefit pension plans and plan investments of defined contribution pension plans. The 2006 Act also permanently extended the pension law changes made by the Economic Growth and Tax Relief Reconciliation Act of 2001, which had been scheduled to sunset on December 31, 2010. Due to the Company’s pension plans’ funded status and funding policy, the Company does not expect the 2006 Act to have a material impact on the Company’s results of operations, financial condition or liquidity when implemented in 2008.

“Other” segment


(in thousands)	Three months ended September 30						% change		Primary reason(s) for significant change
(in thousands)	2007			2006			% change		Primary reason(s) for significant change
Revenues	$	339		$	718		(53	)	Lower investment gains and leveraged lease income, partly offset by a writedown of property held for sale in the third quarter of 2006
Operating loss		(1,896	)		(2,873	)	NM		See explanation for revenues and higher consulting expenses, more than offset by lower compensation expenses
Net loss		(4,725	)		(4,813	)	NM		See explanation for operating loss, partly offset by higher interest expense primarily due to higher medium-term note interest

(in thousands)	Nine months ended September 30						% change		Primary reason(s) for significant change
(in thousands)	2007			2006			% change		Primary reason(s) for significant change
Revenues	$	2,749		$	(934	)	NM		Higher investment gains in 2007 and a writedown of property held for sale in 2006, partly offset by lower leveraged lease income
Operating loss		(7,949	)		(11,593	)	NM		See explanation for revenues and lower compensation expenses, partly offset by higher consulting expenses
Net loss		(15,693	)		(16,571	)	NM		See explanation for operating loss, partly offset by higher interest expense primarily due to higher medium-term note interest

NM Not meaningful.

The “other” business segment includes results of operations of HEI Investments, Inc. (HEIII), a company primarily holding investments in leveraged leases; Pacific Energy Conservation Services, Inc., a contract services company primarily providing windfarm operational and maintenance services to an affiliated electric utility; HEI Properties, Inc. (HEIPI), a company holding passive, venture capital investments; The Old Oahu Tug Service, Inc., which was previously a maritime freight transportation company that ceased operations in 1999 and now is largely inactive; HEI and HEIDI, holding companies; and eliminations of intercompany transactions.

Commitments and contingencies

See Note 7 of HEI’s “Notes to Consolidated Financial Statements” and Note 5 of HECO’s “Notes to Consolidated Financial Statements.”

Recent accounting pronouncements and interpretations

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

FINANCIAL CONDITION

Liquidity and capital resources

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

The consolidated capital structure of HEI (excluding ASB’s deposit liabilities and other borrowings) was as follows as of the dates indicated:


(in millions)	September 30, 2007				December 31, 2006
Short-term borrowings—other than bank	$	101	4	%	$	177	7	%
Long-term debt, net—other than bank		1,230	49			1,133	47
Preferred stock of subsidiaries		34	2			34	1
Common stock equity		1,130	45			1,095	45

	$	2,495	100	%	$	2,439	100	%

As of November 1, 2007, the Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HEI securities were as follows:


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

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

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

S&P also ranks business profiles from “1” (excellent) to “10” (vulnerable). In May 2007, S&P changed HEI’s business profile rank from “6” to “5” and stated that HEI has a satisfactory business profile of “5” and somewhat weak financial measures.

See the electric utilities’ “Liquidity and capital resources” section below for the May 2007 downgrades by S&P of certain HECO, HELCO and MECO ratings.

In December 2006, Moody’s confirmed its issuer ratings and stable outlook for HEI. Moody’s stated, “The rating could be downgraded should weaker than expected regulatory support emerge at HECO, including the continuation of regulatory lag, which ultimately causes earnings and sustainable cash flow to suffer.”

As of September 30, 2007, $96 million of debt, equity and/or other securities were available for offering by HEI under an omnibus shelf registration and an additional $50 million principal amount of Series D notes were available for offering by HEI under its registered medium-term note program.

HEI utilizes short-term debt, principally commercial paper, to support normal operations and for other temporary requirements. HEI also periodically makes short-term loans to HECO to meet HECO’s cash requirements, including the funding of loans by HECO to HELCO and MECO. HEI had an average outstanding balance of commercial paper for the first nine months of 2007 of $68 million and had $71 million outstanding as of September 30, 2007. HEI’s commercial paper increased during the first half of 2007 as a result of HECO retaining its earnings during the second half of 2006 and the first half of 2007 to strengthen its capital structure. The decrease in HECO’s dividend during this period was partly offset by an increase in ASB’s dividend to 100% of its net income. In the third quarter of 2007, HECO resumed paying a dividend to HEI. Management believes that if HEI’s commercial paper ratings were to be downgraded, it may be more difficult for HEI to sell commercial paper under current market conditions.

Effective April 3, 2006, HEI entered into a revolving unsecured credit agreement establishing a line of credit facility of $100 million, with a letter of credit sub-facility, expiring on March 31, 2011, with a syndicate of eight financial institutions. See Note 12 of HEI’s “Notes to Consolidated Financial Statements” for a description of the $100 million credit facility. As of November 1, 2007, the line was undrawn. In the future, the Company may seek to enter into new lines of credit and may also seek to increase the amount of credit available under such lines as management deems appropriate.

For the first nine months of 2007, net cash provided by operating activities of consolidated HEI was $170 million. Net cash used in investing activities for the same period was $132 million primarily due to HECO’s consolidated capital expenditures and ASB’s purchases of investment and mortgage-related securities and a net increase in loans receivable, partly offset by repayments of investment and mortgage-related securities. Net cash used by financing activities during this period was $69 million as a result of several factors, including net decreases in deposit liabilities, short-term borrowings and cash overdrafts and the payment of common stock dividends, partly offset by net increases in other bank borrowings and long-term debt and proceeds from the issuance of common stock under HEI plans.

Selected contractual obligations and commitments

Deferred tax liabilities ($95 million as of September 30, 2007 and $107 million as of December 31, 2006), FIN 48 liabilities ($13 million as of September 30, 2007) and accrued interest related to uncertain tax positions ($2 million as of September 30, 2007) have not been included in HEI’s consolidated table of “Selected contractual obligations and commitments” in HEI’s Form 10-K because the Company cannot reliably estimate when, and to what extent, cash settlement of these liabilities will occur.

CERTAIN FACTORS THAT MAY AFFECT FUTURE RESULTS AND FINANCIAL CONDITION

The Company’s results of operations and financial condition can be affected by numerous factors, many of which are beyond the Company’s control and could cause future results of operations to differ materially from historical results. For information about certain of these factors, see pages 82 to 89 of HEI’s 2006 Form 10-K.

Additional factors that may affect future results and financial condition are described on page iv under “Forward-Looking Statements.”

MATERIAL ESTIMATES AND CRITICAL ACCOUNTING POLICIES

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

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

For information about these material estimates and critical accounting policies, see pages 90 to 93 of HEI’s 2006 Form 10-K.

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

ELECTRIC UTILITIES

RESULTS OF OPERATIONS


(dollars in thousands, except per barrel amounts)	Three months ended September 30				% change		Primary reason(s) for significant change
(dollars in thousands, except per barrel amounts)	2007		2006		% change		Primary reason(s) for significant change
Revenues	$	567,615	$	569,838	—		Reserve accrued for the potential refund of a portion of HECO’s 2005 test year interim rate increase ($15 million), discontinuation of DSM lost margin and shareholder incentives ($2 million) and lower KWH sales ($1 million), partly offset by HELCO’s 2006 test year interim rate relief ($6 million), proceeds from sale of non-electric utility property ($5 million), higher fuel oil and purchased energy fuel costs, the effects of which are generally passed on to customers ($4 million) and higher amounts of DSM costs recovered through surcharges ($2 million)
Expenses
Fuel oil		222,721		227,288	(2	)	Lower KWHs generated and increased efficiency, partly offset by higher fuel oil prices
Purchased power		144,918		138,758	4		Higher KWHs purchased and higher fuel costs
Other		168,610		155,141	9		Higher other O&M ($12 million) and depreciation expenses ($2 million)
Operating income		31,366		48,651	(36	)	Lower revenues and higher expenses
Net income		12,875		23,666	(46	)	Lower operating income and AFUDC and higher interest expense, partly offset by lower income taxes *
Kilowatthour sales (millions)		2,663		2,678	(1	)	Conservation, partly offset by load growth and warmer weather
Oahu cooling degree days		1,566		1,469	7
Average fuel oil cost per barrel	$	74.78	$	74.35	1


(dollars in thousands, except per barrel amounts)	Nine months ended September 30				% change		Primary reason(s) for significant change
(dollars in thousands, except per barrel amounts)	2007		2006		% change		Primary reason(s) for significant change
Revenues	$	1,508,005	$	1,548,861	(3	)	Lower fuel oil and purchased energy fuel costs, the effects of which are generally passed on to customers ($48 million), reserve accrued for the potential refund of a portion of HECO’s 2005 test year interim rate increase ($15 million) and discontinuation of DSM lost margin and shareholder incentives ($5 million), partly offset by HELCO’s 2006 test year interim rate relief ($12 million), 0.5% higher KWH sales ($8 million), proceeds from sale of non-electric utility property ($5 million) and higher amounts of DSM costs recovered through surcharges ($5 million)
Expenses
Fuel oil		549,771		594,940	(8	)	Lower fuel oil costs and fewer KWHs generated
Purchased power		390,161		378,916	3		Higher KWHs purchased and higher capacity and non-fuel charges, partly offset by lower fuel costs
Other		494,926		440,928	12		Higher other O&M ($41 million) and depreciation expenses ($5 million) and write-off of HELCO plant in service ($12 million), partly offset by lower taxes, other than income taxes ($4 million)
Operating income		73,147		134,077	(45	)	Lower revenues and higher expenses
Net income		23,978		61,940	(61	)	Lower operating income and AFUDC, partly offset by lower income taxes *
Kilowatthour sales (millions)		7,568		7,528	1		Load growth and warmer weather, partly offset by conservation
Oahu cooling degree days		3,666		3,321	10
Average fuel oil cost per barrel	$	65.52	$	69.09	(5	)

*	The electric utilities had an effective tax rate of 34% for the first nine months of 2007, compared to 38% for the first nine months of 2006 (see Note 8 in HECO’s “Notes to Consolidated Financial Statements”).

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

Results – three months ended September 30, 2007

Operating income for the third quarter of 2007 decreased 36% from the same period in 2006 due primarily to a $15 million reserve accrued for the potential refund of a portion of HECO’s 2005 test year interim rate increase (see “Most recent rate requests – HECO – 2005 test year rate case” below), higher other O&M and depreciation expenses, lower KWH sales, and the discontinuation of DSM lost margin and shareholder incentives, partly offset by interim rate relief granted to HELCO by the PUC in April 2007 ($6 million) and a gain from the sale of non-electric utility property (see Note 12 in HECO’s “Notes to Consolidated Financial Statements”). KWH sales in the third quarter of 2007 decreased 0.6% from the same period in 2006, primarily due to increased energy conservation, partly offset by new load growth (i.e., increase in number of customers and new construction) and warmer weather. Other operation expense increased 16% primarily due to higher administrative and general expenses, including retirement benefits expense, DSM expenses and costs to ensure reliable operations. Pension and other postretirement benefit expenses for the electric utilities increased $1 million over the same period in 2006, primarily due to the adoption of a 50 basis points lower asset return rate as of December 31, 2006 by the HEI Pension Investment Committee and expenses

related to the adoption of the pension and OPEB tracking mechanisms at HELCO, including the amortization of its $12.8 million prepaid pension asset, which became effective in April 2007 (based on an interim order by the PUC in HELCO’s test year 2006 rate case; see “Most recent rate requests”). Maintenance expense increased by 21% due to higher production maintenance expense ($5.4 million) resulting primarily from higher generating station maintenance and the greater number and scope of generating unit overhauls. Higher depreciation expense was attributable to additions to plant in service in 2006 (including HECO’s New Dispatch Center and Ford Island Substation, and MECO’s M18 generating unit).

Results – nine months ended September 30, 2007

Operating income for the first nine months of 2007 decreased 45% from the same period in 2006 due primarily to a $15 million reserve accrued for the potential refund of a portion of HECO’s 2005 test year interim rate increase, higher other O&M expenses, a first quarter 2007 $12 million write-off of plant in service costs associated with the CT-4 and CT-5 generating units at the Keahole generating station and the discontinuation of DSM lost margin and shareholder incentives, partly offset by higher KWH sales, interim rate relief granted to HELCO by the PUC in April 2007 ($12 million) and gain from the sale of non-electric utility property. KWH sales in the first nine months of 2007 increased 0.5% from the same period in 2006, primarily due to new load growth and warmer weather, partially offset by increased energy conservation. Other operation expense increased 13% primarily due to higher administrative and general expense, including retirement benefits expense, higher DSM expenses and costs to ensure reliable operations. Pension and other postretirement benefit expenses for the electric utilities increased $4 million over the same period in 2006 primarily due to the adoption of a 50 basis points lower asset return rate as of December 31, 2006 by the HEI Pension Investment Committee and expenses related to the adoption of the pension and OPEB tracking mechanisms at HELCO, including the amortization of its prepaid pension asset, which became effective in April 2007 (approved on an interim basis by the PUC in HELCO’s test year 2006 rate case; see “Most recent rate requests”). Maintenance expense increased by 36% due to higher production maintenance expense ($18.8 million resulting primarily from the greater number and scope of generating unit overhauls and higher generating station maintenance) and transmission and distribution maintenance expense ($3.9 million resulting primarily from higher vegetation management and substation maintenance expenses). Higher depreciation expense was attributable to additions to plant in service in 2006.

The trend of increased other O&M expenses is expected to continue as the electric utilities expect (1) higher DSM expenses (that are generally passed on to customers through a surcharge, including additional expenses for programs that have been approved pursuant to a final D&O in an energy efficiency DSM Docket) and integrated resource planning expenses, (2) higher employee benefit expenses, primarily for retirement benefits, and (3) higher production expenses, primarily to support the higher demand that has occurred over the last five years.

As a result of load growth on Oahu and other factors, there currently is an increased risk to generation reliability that is expected to continue at least until HECO installs its planned new generating unit in 2009. Existing units are running harder, resulting in more frequent and more extensive maintenance, at times requiring temporary shut downs of these units. Generation reserve margins on Oahu continue to be strained, particularly during peak periods. HECO has taken a number of steps to mitigate the risk of outages, including securing additional purchased power, adding DG at some substations and encouraging energy conservation. The marginal costs of supplying growing demand, however, are increasing because of the decreasing reserve margin situation, and the trend of cost increases is not likely to ease.

Competition

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

In March 2000, the PUC approved a standard form contract for customer retention that allows HELCO to provide a rate option for customers who would otherwise reduce their energy use from HELCO’s system by using energy from a nonutility generator. Based on HELCO’s current rates, the standard form contract provides a 10% discount on base energy rates for qualifying “Large Power” and “General Service Demand” customers. In November 2006, HELCO entered into three-year standard form contracts with two of its hotel customers.

In October 2003, the PUC opened investigative proceedings on two specific issues (competitive bidding and DG) to move toward a more competitive electric industry environment under cost-based regulation.

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

The parties in the proceeding included the Consumer Advocate, HECO, HELCO, MECO, Kauai Island Utility Cooperative (KIUC) and Hawaii Renewable Energy Alliance (HREA), a renewable energy organization. The issues addressed in the proceeding included whether a competitive bidding system should be developed for acquiring or building new generation and, if so, how a fair system can be developed that “ensures that competitive benefits result from the system and ratepayers are not placed at undue risk,” what the guidelines and requirements for prospective bidders should be, and how such a system can encourage broad participation.

On June 30, 2006, the PUC issued a decision in this proceeding, which included a proposed framework to govern competitive bidding as a mechanism for acquiring or building new generation in Hawaii and required the parties to submit comments on the proposed framework. On December 8, 2006, the PUC issued a decision which reviewed the parties’ comments and revised the competitive bidding framework, which became effective upon issuance of the decision. The final framework states, among other things, that: (1) a utility is required to use competitive bidding to acquire a future generation resource or a block of generation resources unless the PUC finds bidding to be unsuitable, (2) the determination of whether to use competitive bidding for a future generation resource or a block of generation resources will be made by the PUC during its review of the utility’s IRP, (3) an exemption from the framework is granted for cooperatively-owned utilities, (4) the framework does not apply to two pending projects (HECO’s CIP-1 and HELCO’s ST-7), MECO’s M-18 project (which went into commercial operation in October 2006), specifically identified offers to sell energy on an as-available basis or to sell firm energy and/or capacity by non-fossil fuel producers that were under review by an electric utility at the time this framework was adopted (provided that negotiations with the non-fossil fuel producers for firm capacity are completed no later than December 31, 2007), and certain other situations identified in the framework, (5) waivers from competitive bidding for certain circumstances will be considered by the PUC and granted when considered appropriate, (6) for each project that is subject to competitive bidding, the utility is required to submit a report on the cost of parallel planning upon the PUC’s request, (7) the utility is required to consider the effects on competitive bidding of not allowing bidders access to utility-owned or controlled sites, and to present reasons to the PUC for not allowing site access to bidders when the utility has not chosen to offer a site to a third party, (8) the utility is required to select an independent observer from a list approved by the PUC whenever the utility or its affiliate seeks to advance a project proposal (i.e., in competition with those offered by bidders) in response to a need that is addressed by its Request for Proposal (RFP) or when the PUC otherwise determines, (9) the evaluation of the utility’s bid should account for the possibility that the capital or running costs actually incurred, and recovered from ratepayers, over the plant’s lifetime, will vary from the levels assumed in the utility’s bid, (10) the utility may consider its own self-bid proposals in response to generation needs identified in its RFP and (11) for any resource to which competitive bidding does not apply (due to waiver or exemption), the utility retains its traditional obligation to offer to purchase capacity and energy from a Qualifying Facility (QF) at avoided cost upon reasonable terms and conditions approved by the PUC. In the first half of 2007, the utilities filed proposed tariffs containing procedures for interconnection and transmission upgrades, a list of qualified candidates for the Independent Observer position for future competitive bidding processes and a proposed Code of Conduct. The PUC approved the list of candidate Independent Observers and the Code of Conduct.

On September 28, 2007, HECO issued a “Solicitation of Interest” seeking developers who are interested in entering a competitive bidding process to supply added renewable energy to Oahu’s power grid. Subject to PUC approval, HECO then plans to follow up with a formal Request for Proposals (RFP). The proposed RFP is anticipated to ask bidders to submit a base proposal for their project to provide up to 100 MW of non-firm renewable energy and may also allow bidders to submit additional alternate larger proposals or subsequent phased increments of more renewable energy. On October 9, 2007, in response to HECO’s request for approval to proceed with the proposed RFP and approval of a HECO contract with an Independent Observer for that effort, the PUC issued an order opening a new docket to receive filings, review approval requests, and resolve disputes, if necessary, related to HECO’s proposed RFP. The order also identified HECO and the Consumer Advocate as parties to this new docket

and approved HECO’s contract with the Independent Observer for the proposed RFP. The PUC also stated in its order that once the remaining issue related to approval of the utilities proposed interconnection and transmission tariffs is resolved, the competitive bidding docket will be closed.

Management cannot currently predict the ultimate effect of these decision/orders on the ability of the electric utilities to acquire or build additional generating capacity in the future.

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

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

With regard to DG ownership, the D&O affirmed the ability of the electric utilities to procure and operate DG for utility purposes at utility sites. The PUC also indicated its desire to promote the development of a competitive market for customer-sited DG. In weighing the general advantages and disadvantages of allowing a utility to provide DG services on a customer’s site, the PUC found that the “disadvantages outweigh the advantages.” However, the PUC also found that the utility “is the most informed potential provider of DG” and it would not be in the public interest to exclude the electric utilities from providing DG services at this early stage of DG market development. Therefore, the D&O allows the utility to provide DG services on a customer-owned site as a regulated service when (1) the DG resolves a legitimate system need, (2) the DG is the lowest cost alternative to meet that need, and (3) it can be shown that, in an open and competitive process acceptable to the PUC, the customer operator was unable to find another entity ready and able to supply the proposed DG service at a price and quality comparable to the utility’s offering.

In April 2006, the PUC provided clarification to the conditions under which the electric utilities are allowed to provide regulated DG services (e.g., the utilities can use a portfolio perspective—a DG project aggregated with other DG systems and other supply-side and demand-side options—to support a finding that utility-owned customer-sited DG projects fulfill a legitimate system need, and the economic standard of “least cost” in the order means “lowest reasonable cost” consistent with the standard in the IRP framework), and affirmed that the electric utility has the responsibility to demonstrate that it meets all applicable criteria included in the D&O in its application for PUC approval to proceed with a specific DG project.

The electric utilities are evaluating potential DG projects. In July 2006, MECO filed an application for PUC approval of an agreement for the installation of a CHP system at a hotel site on the island of Lanai. On September 11, 2006, the PUC issued a Schedule of Proceedings for its consideration of this CHP project. The Consumer Advocate did not object to approval of MECO’s application with the qualification that no determination be made at this time as to whether the costs associated with installation of the CHP system can be included in MECO’s revenue requirements. MECO’s response, filed in February 2007, explained that the Consumer Advocate’s conditions would not allow MECO to proceed with the project as such a conditional approval would not provide reasonable assurance that MECO will be able to include the associated costs in its revenue requirement. MECO requested that the PUC approve the CHP agreement, approve inclusion of the fuel and transportation costs and associated taxes in MECO’s ECAC and allow MECO to include the costs incurred in its revenue requirement for ratemaking purposes. In April 2007, MECO submitted a system economic analysis to the Consumer Advocate to address the Consumer Advocate’s concerns and to enable MECO and the Consumer Advocate to reach a stipulation on the issues in the docket. The parties are discussing a possible stipulation.

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

the third quarter of 2006. The Consumer Advocate stated that it did not object to implementation of the interconnection and standby rate tariffs at the present time, but reserved the right to review the reasonableness of both tariffs in rate proceedings for each of the utilities.

Distributed generation tariff proceeding. By order dated December 28, 2006, the PUC opened a new proceeding to investigate the utilities’ proposed DG interconnection tariff modifications and standby rate tariffs. Public hearings were held in February and March 2007. In April 2007, the PUC granted intervenor status to HREA, a group of hotel and resort companies, a group consisting of a CHP vendor, a hotel company and a hospital management company, a senior living community company and the United States Combined Heat and Power Association. In September 2007, all Parties except HREA executed and filed a stipulation for approval of the electric utilities’ proposed DG interconnection tariffs. In October 2007, the electric utilities filed modified standby service tariffs and their statement of position on their proposed standby service tariffs. The other parties are required to file position statements by November 16, 2007. A prehearing conference is tentatively scheduled for January/February 2008.

Most recent rate requests

The electric utilities initiate PUC proceedings from time to time to request electric rate increases to cover rising operating costs and the cost of plant and equipment, including the cost of new capital projects to maintain and improve service reliability. The PUC may grant an interim increase within 10 to 11 months following the filing of the application, but there is no guarantee of such an interim increase or its amount and amounts collected are refundable, with interest, to the extent they exceed the amount approved in the final D&O. The timing and amount of any final increase is determined in the discretion of the PUC. The adoption of revenue, expense, rate base and cost of capital amounts (including the return on average common equity and return on rate base) for purposes of an interim rate increase does not commit the PUC to accept any such amounts in its final D&O.

As of November 1, 2007, the return on average common equity (ROACE) found by the PUC to be reasonable in the most recent final rate decision for each utility was 11.40% for HECO (D&O issued on December 11, 1995, based on a 1995 test year), 11.50% for HELCO (D&O issued on February 8, 2001, based on a 2000 test year) and 10.94% for MECO (amended D&O issued on April 6, 1999, based on a 1999 test year). The ROACEs used by the PUC for purposes of HECO’s 2005 test year rate case amended proposed final D&O and the interim rate increases in HECO’s and HELCO’s rate cases based on 2007 and 2006 test years, respectively, were 10.70%.

For the 12 months ended June 30, 2007, the simple average ROACEs (calculated under the ratemaking method and reported to the PUC semi-annually) for HECO, HELCO and MECO were 5.49%, 0.42%, and 7.58%, respectively; if AOCI charges due to SFAS No. 158 were excluded, the ROACEs for HECO and MECO would have been 5.11% and 7.32%, respectively (HELCO’s ROACE calculation excludes the AOCI charges as a result of an interim D&O). As a result of the interim D&O in HECO’s 2007 test year rate case, HECO’s equity will be adjusted for the impact of AOCI charges, effective in the fourth quarter of 2007. HECO’s actual ROACE continues to be significantly lower than its allowed ROACE primarily because of increased other O&M expenses, which are expected to continue and have resulted in HECO seeking rate relief more often than in the past. The interim rate relief granted to HECO by the PUC in September 2005 and in October 2007 (see below) was based in part on increased costs of operating and maintaining HECO’s system. HELCO’s ROACE was negatively impacted by the write-off of certain CT-4 and CT-5 costs and the fact that its electric rates did not change for the unit additions until the PUC granted interim rate relief, implemented on April 5, 2007, in the HELCO 2006 rate case (see below).

As of November 1, 2007, the return on rate base (ROR) found by the PUC to be reasonable in the most recent final rate decision for each utility was 9.16% for HECO, 9.14% for HELCO and 8.83% for MECO (D&Os noted above). The RORs used for purposes of the interim D&Os in the HECO and HELCO rate cases based on 2007 and 2006 test years were 8.62% and 8.33%, respectively. The ROR used for purposes of the amended proposed final D&O in HECO’s 2005 test year rate case was 8.66%. For the 12 months ended June 30, 2007, the simple average RORs (calculated under the ratemaking method and reported to the PUC semi-annually) for HECO, HELCO and MECO were 5.08%, 4.77% and 6.59%, respectively.

By reason of the adoption of SFAS No. 158, MECO may in the future have significant charges to AOCI related to the funded status of its retirement benefit plan, which decreases its common stock equity. Absent appropriate regulatory relief to adjust for the impact on equity of these AOCI charges, which MECO has requested in its recent rate case, the resulting increase in its RORs and ROACEs could impact the rates it is allowed to charge, which may ultimately result in reduced revenues and lower earnings. HELCO and HECO received interim D&Os in their 2006 and 2007 test year rate cases, respectively, which included the reclassification to a regulatory asset of the charge for retirement benefits that would otherwise be recorded in AOCI in the second and fourth quarter of 2007, respectively (see Note 4 of HECO’s “Notes to Consolidated Financial Statements”).

HECO.

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

In March 2005, the PUC issued a bifurcation order separating HECO’s requests for approval and/or modification of its existing and proposed DSM programs from the rate case proceeding into a new docket (EE DSM Docket). The issues for the EE DSM Docket included (1) whether, and if so, what, energy efficiency goals should be established, (2) whether the proposed and/or other DSM programs will achieve the established energy efficiency goals and be implemented in a cost-effective manner, (3) what market structures are most appropriate for providing these or other DSM programs, (4) for utility-incurred costs, what cost recovery mechanisms and cost levels are appropriate, (5) whether, and if so, what incentive mechanisms are appropriate to encourage the implementation of DSM programs, and (6) which DSM programs should be approved, modified, or rejected. See “Other regulatory matters—Demand-side management programs” below for a discussion of the PUC’s D&O issued in the EE DSM Docket on February 13, 2007.

In September 2005, HECO, the Consumer Advocate and the DOD reached agreement (subject to PUC approval) on most of the issues in the rate case proceeding, excluding the portion of the original rate case bifurcated into the EE DSM Docket. The remaining significant issue not resolved among the parties was the appropriateness of including in rate base approximately $50 million related to HECO’s prepaid pension asset, net of deferred income taxes.

Later in September 2005, the PUC issued its interim D&O (with tariff changes implemented on September 28, 2005). For purposes of the interim D&O, the PUC included HECO’s prepaid pension asset in rate base (with an annual rate increase impact of approximately $7 million).

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


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

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

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

2007 test year rate case. On December 22, 2006, HECO filed a request with the PUC for a general rate increase of $99.6 million, or 7.1% over the electric rates currently in effect (i.e., including the interim rate increase discussed above of $53 million ($41 million net additional revenues) granted by the PUC in September 2005), based on a 2007 test year, an 8.92% ROR, an 11.25% ROACE and a $1.214 billion average rate base. If the additional revenues from the interim increase were ultimately not included in rates in the final D&O in HECO’s 2005 test year rate case, the total increase requested would be $151.5 million. This rate case excluded DSM surcharge revenues and associated incremental DSM costs because certain DSM issues, including cost recovery, were being addressed in the EE DSM Docket.

HECO’s application includes a proposed new tiered rate structure for residential customers to reward customers who practice energy conservation with lower electric rates for lower monthly usage. The proposed rate increase includes costs incurred to maintain and improve reliability, such as the new Dispatch Center building and associated equipment and the Energy Management System that became operational in 2006, new substations, a new outage management system (added in the second quarter of 2007) and increased O&M expenses.

The application addresses the ECAC provisions of Act 162 and requests the continuation of HECO’s ECAC. On December 29, 2006, the electric utilities’ Report on Power Cost Adjustments and Hedging Fuel Risks (ECAC Report) prepared by their consultant, National Economic Research Associates, Inc., was filed with the PUC. The testimonies filed in the latest rate cases for HECO, HELCO and MECO included or incorporated the ECAC Report, which concluded that (1) the electric utilities’ ECACs are well-designed, and benefit the electric utilities and their ratepayers and (2) the ECACs comply with the statutory requirements of Act 162. With respect to hedging, the consultants concluded that (1) hedging of oil by HECO would not be expected to reduce fuel and purchased power costs and in fact would be expected to increase the level of such costs and (2) even if rate smoothing is a desired goal, there may be more effective means of meeting the goal, and there is no compelling reason for the electric utilities to use fuel price hedging as the means to achieving the objective of increased rate stability.

HECO’s application requests a return on HECO’s pension assets (i.e., accumulated contributions in excess of accumulated net periodic pension costs) by including such assets (net of deferred taxes) in rate base. In a separate

AOCI proceeding, the electric utilities requested PUC approval to record as a regulatory asset for financial reporting purposes, the amounts that would otherwise be charged to AOCI in stockholders’ equity as a result of adopting SFAS No. 158, which request was denied. HECO has proposed in the rate case to restore to book equity for ratemaking purposes the amounts charged to AOCI as a result of adopting SFAS No. 158. The authorized ROACE found to be fair in a rate case is applied to the equity balance in determining the utility’s weighted cost of capital, which is the rate of return applied to the rate base in determining the utility’s revenue requirements. If the reduction in equity balance resulting from the AOCI charges is not restored for ratemaking purposes, the utility’s position is that a higher ROACE will be required. In a June 2007 update to its direct testimonies, HECO proposed pension and OPEB tracking mechanisms, similar to the mechanisms that were agreed to by HELCO and the Consumer Advocate and approved on an interim basis by the PUC in the HELCO 2006 test year rate case. A pension funding study (required by the PUC in the AOCI proceeding) was filed in the HECO rate case in May 2007. The conclusions in the study were consistent with the funding practice proposed with the pension tracking mechanism.

In March 2007, a public hearing on the rate case was held. In April 2007, the PUC granted the DOD’s motion to intervene.

On September 6, 2007, HECO, the Consumer Advocate and the DOD (the parties) executed and filed an agreement on most of the issues in HECO’s 2007 test year rate case and HECO submitted a statement of probable entitlement with the PUC. The agreement was subject to approval by the PUC.

The amount of the revenue increase based on the stipulated agreement was $69.997 million annually, or a 4.96% increase over current effective rates at the time of the stipulation. The settlement agreement included, as a negotiated compromise of the parties’ respective positions, a return on average common equity of 10.7% (and an 8.62% return on average rate base of $1.158 billion) to determine revenue requirements in the proceeding. In the settlement agreement, the parties agreed that the final rates set in HECO’s 2005 test year rate case may impact revenues at current effective rates and at present rates, and the amount of the stipulated interim rate increase will be adjusted to take into account any such changes.

A significant unsettled issue among the parties impacting the amount of the increase is the appropriateness of including in rate base approximately $36 million related to HECO’s pension asset (accumulated contributions to its pension fund in excess of accumulated net periodic pension cost), net of deferred income taxes. HECO management’s position was that its proposal to include the pension asset, net of deferred income taxes, in rate base is reasonable. If HECO were to prevail on this open issue, the additional annual revenue increase would be approximately $5.5 million. In the amended proposed final D&O in the 2005 test year rate case, however, the PUC excluded HECO’s pension asset in determining rate base, resulting in an accrual for potential customer refunds in the third quarter of 2007.

In total, based on the settlement agreement and HECO’s position on the unsettled issues, HECO’s requested increase was reduced from $99.6 million, or 7.1% over the electric revenues currently in effect (i.e., including the interim rate increase), to $75.5 million, or 5.3%.

HECO proposed, and the Consumer Advocate and the DOD accepted, the adoption of a pension tracking mechanism, which is intended to smooth the impact to ratepayers of potential fluctuations in pension costs. See Note 4, “Retirement benefits,” of HECO’s Notes to Consolidated Financial Statements.

In accordance with Act 162 of the 2006 Session Laws of Hawaii, the PUC, by an order issued August 24, 2007, added as an issue to be addressed in the rate case whether HECO’s ECAC complies with the requirements of Hawaii Revised Statutes §269-16(g). In the settlement agreement, the parties agreed that the ECAC should continue in its present form for purposes of an interim rate increase and stated that they are continuing discussions with respect to the final design of the ECAC to be proposed for approval in the final D&O. The parties will file proposed findings of fact and conclusions of law on all issues in this proceeding, including the ECAC, and the schedule for that filing is being determined. The parties agreed that their resolution of this issue would not affect their agreement regarding revenue requirements in the proceeding.

On October 22, 2007, the PUC issued, and HECO implemented, an interim D&O granting HECO an increase of $69.997 million in annual revenues over current effective rates at the time of the interim decision, subject to refund with interest. The interim increase is based on the settlement agreement described above. See “Interim increases” in Note 5 and Note 4, “Retirement benefits,” of HECO’s “Notes to Consolidated Financial Statements.”

Management cannot predict the timing, or the ultimate outcome, of HECO’s 2007 test year rate case.

HELCO. In May 2006, HELCO filed a request with the PUC to increase base rates by $29.9 million, or 9.24% in annual base revenues, based on a 2006 test year, an 8.65% ROR, an 11.25% ROACE and a $369 million average rate base. HELCO’s application includes a proposed new tiered rate structure, which would enable most residential users to see smaller increases in the range of 3% to 8%. The tiered rate structure is designed to minimize the increase for residential customers using less electricity and is expected to encourage customers to take advantage of solar water heating programs and other energy management options. In addition, HELCO’s application proposes new time-of-use service rates for residential and commercial customers. The proposed rate increase would pay for improvements made to increase reliability, including transmission and distribution line improvements and the two generating units at the Keahole power plant (CT-4 and CT-5), and increased O&M expenses. The application requests the continuation of HELCO’s ECAC.

The PUC held public hearings on HELCO’s application in June 2006. The PUC granted Keahole Defense Coalition’s motion to participate in this proceeding. In February 2007, the Consumer Advocate submitted its testimony in the proceeding, recommending a revenue increase of $16.6 million based on its proposed ROR of 7.95%, a ROACE ranging between 9.50% and 10.25% and a proposed average rate base of $345 million. The Consumer Advocate recommended adjustments of $21.5 million to HELCO’s rate base for a portion of CT-4 and CT-5 costs (primarily relating to HELCO’s AFUDC, land use permitting costs, and related litigation expenses). In the filing, the Consumer Advocate’s consultant concluded that HELCO’s ECAC provides a fair sharing of the risks of fuel cost changes between HELCO and its ratepayers in a manner that preserves the financial integrity of HELCO without the need for frequent rate filings.

Keahole Defense Coalition (whose participation in the proceeding is limited) submitted a Position Statement in which it contended that the PUC should exclude from rate base a greater amount of the CT-4 and CT-5 costs than proposed by the Consumer Advocate.

In March 2007, HELCO submitted its rebuttal to the Consumer Advocate’s testimony and the Keahole Defense Coalition’s statement of position. In April 2007, Keahole Defense Coalition filed a responsive statement to HELCO’s rebuttal testimonies to which HELCO responded in May 2007.

In March and May 2007, HELCO and the Consumer Advocate reached settlement agreements on all revenue requirement and rate design issues in the HELCO 2006 rate case proceeding. The PUC may accept or reject the settlement agreements or any part of them. If the PUC does not accept the material terms of the agreements, either (or both) of the parties, may withdraw from the agreements and may pursue their respective positions in the proceeding without prejudice. Under the revenue requirement agreement, HELCO agreed to write-off a portion of CT-4 and CT-5 costs, which resulted in an after-tax charge of approximately $7 million in the first quarter of 2007.

On April 4, 2007, the PUC issued an interim D&O, which was implemented on April 5, 2007, granting HELCO an increase of 7.58%, or $24.6 million in annual revenues, over revenues at present rates for a normalized 2006 test year. The interim increase reflects the settlement of the revenue requirement issues reached between HELCO and the Consumer Advocate and is based on an average rate base of $357 million (which reflects the write-off of a portion of CT-4 and CT-5 costs) and a return on average rate base of 8.33% (incorporating a rate of return on average common equity of 10.7%). In the interim D&O, the PUC also approved on an interim basis the adoption of pension and OPEB tracking mechanisms (see Note 4 of HECO’s “Notes to Consolidated Financial Statements”).

MECO. In February 2007, MECO filed a request with the PUC to increase base rates by $19.0 million, or 5.3% in annual base revenues, based on a 2007 test year, an 8.98% ROR, an 11.25% ROACE and a $386 million average rate base. MECO’s application includes a proposed new tiered rate structure for residential customers to reward customers who practice energy conservation with lower electric rates for lower monthly usage. The proposed rate increase would pay for improvements to increase reliability, including two new generating units added since MECO’s last rate case (which was based on a 1999 test year) at its Maalaea Power plant (M19, a 20 MW combustion turbine placed in service in 2000 and M18, an 18 MW steam turbine placed in service in October 2006 to complete the installation of a second dual-train combined cycle unit), and transmission and distribution infrastructure improvements. The proposed rate structure also includes continuation of MECO’s ECAC. The application requests a return on MECO’s pension assets (i.e., accumulated contributions in excess of accumulated net periodic pension costs) by including such assets (net of deferred income taxes) in rate base. The application also proposes to restore book equity (in determining the equity balance for ratemaking purposes) for the amounts that were charged against equity (i.e., to AOCI) as a result of recording a pension and other postretirement benefits liability after implementing SFAS No. 158.

In an update to its direct testimonies filed in September 2007, MECO proposed a lower increase in annual revenues of $18.3 million, or 5.1%, but its request continued to be based on an 8.98% ROR and an 11.25% ROACE. Also in the update, MECO proposed tracking mechanisms for pension and OPEB, similar to the mechanisms proposed by HECO and HELCO, and approved by the PUC on an interim basis, in their 2007 and 2006 test year rate cases, respectively. In October 2007, the Consumer Advocate filed its direct testimony which recommended a revenue increase of $8.9 million, based on a ROR of 8.29% and a ROACE of 10.0%. The difference between MECO’s and the Consumer Advocate’s proposed increase is primarily caused by the Consumer Advocate’s lower recommended ROR and ROACE.

The PUC held public hearings on MECO’s application in April 2007. Evidentiary hearings are scheduled for December 2007.

Other regulatory matters

Demand-side management programs. On February 13, 2007, the PUC issued its D&O in the EE DSM Docket that had been opened by the PUC to bifurcate the EE DSM issues originally raised in the HECO 2005 test year rate case. In the D&O, the PUC authorized HECO to implement its eight proposed EE DSM programs (which include enhancements to its six existing programs, and two new programs, the Residential Low Income (RLI) and the Residential Customer Energy Awareness (RCEA) Programs), with certain modifications. In approving the EE DSM portfolio, the PUC found that: (1) the EE DSM portfolio should achieve Energy Efficiency goals and should be implemented in a cost-effective manner and (2) the EE DSM programs are necessary to help address HECO’s current reserve capacity shortfall.

In addition, the PUC required that the administration of all EE DSM programs be turned over to a non-utility, third-party administrator, with the transition to the administrator, funded through a public benefits fund (PBF) surcharge, to become effective around January 2009. The PUC opened a new docket to select a third-party administrator and to refine details of the new market structure in an Order issued in September 2007. In the Order, the PUC stated that it “intends to solicit bids for the PBF Administrator through an RFP or other appropriate procedure.” Furthermore, “[u]pon selection of the PBF Administrator, the commission intends, in this docket, to determine whether the HECO Companies will be allowed to compete for the implementation of the Energy Efficiency DSM programs.” A timeline for the proceeding has not been determined.

Unlike the EE DSM programs, load management DSM programs (see below) will continue to be administered by the utilities. The utilities also may compete for implementation of the EE DSM programs and the RCEA Program and the PUC did not determine any of the parameters of the eligibility of HECO or its subsidiaries or the selection criteria that will be used in awarding program implementation.

The D&O also provides for HECO’s recovery of DSM program costs and utility incentives. With respect to cost recovery, the PUC continues to permit recovery of reasonably-incurred DSM implementation costs, under the Integrated Resource Plan (IRP) framework. DSM utility incentives will be derived from a graduated performance-based schedule of net system benefits. In order to qualify for an incentive, the utility must meet MW and MWh reduction goals for its EE DSM programs in both the commercial and industrial sector, and the residential sector. The amount of the annual incentive is capped at $4 million for HECO, and may not exceed either 5% of the net system benefits, or utility earnings opportunities foregone by implementing DSM programs in lieu of supply-side rate based investments. Negative incentives will not be imposed for underperformance.

On March 8, 2007, HECO filed a motion for clarification and/or partial reconsideration of the D&O requesting, among other things, clarification of certain energy efficiency goals for 2007 and 2008, reconsideration of HECO’s request for budget flexibility which would allow HECO to increase its DSM program budget within certain limits without PUC approval, and clarification of the calculation of the DSM utility incentive. On May 21, 2007, the PUC clarified the 2007 and 2008 energy efficiency goals and the calculation of the DSM utility incentive, and rejected HECO’s request for budget flexibility, but did grant HECO the ability to request program modifications by letter request. Since that time, the PUC has approved budget increases and program modifications for various DSM programs.

In October 2007, the PUC opened a proceeding for the review of the utilities’ DSM reports and program modifications.

In 2004, HECO and the Consumer Advocate reached agreement on a residential load management program and a commercial and industrial load management program and the PUC approved HECO’s programs. Implementation of these programs began in early 2005. The residential load management program includes a monthly electric bill credit for eligible customers who participate in the program, which allows HECO to disconnect the customer’s residential electric water heaters from HECO’s system to reduce system load when deemed necessary by HECO. The commercial and industrial load management program provides an incentive on the portion of the demand load that eligible customers allow to be controlled or interrupted by HECO. In addition, if HECO interrupts the load, an incentive is paid on the kilowatthours interrupted.

Avoided cost generic docket. In May 1992, the PUC instituted a generic investigation, including all of Hawaii’s electric utilities, to examine the proxy method and formula used by the electric utilities to calculate their avoided energy costs and Schedule Q rates. In general, Schedule Q rates are available to customers with cogeneration and/or small power production facilities with a capacity of 100 KWHs or less who buy power from or sell power to the electric utility. The parties to the 1992 docket include the electric utilities, the Consumer Advocate, the DOD, and representatives of existing or potential IPPs. In March 1994, the parties entered into and filed a Stipulation to Resolve Proceeding, which is subject to PUC approval. The parties could not reach agreement with respect to certain of the issues, which are addressed in Statements of Position filed in March 1994. In July 2004, the PUC ordered the parties to review and update the agreements, information and data contained in the stipulation and file such information. On December 29, 2006, the parties filed an Updated Stipulation to Resolve Proceeding with the PUC. The parties agreed that avoided fuel costs, except for Lanai and Molokai, will be determined using a computer production simulation model and agreed on certain parameters that would be used to calculate avoided costs. The parties were not in total agreement on certain other issues which will need to be decided by the PUC. HECO and its subsidiaries, the Consumer Advocate and the DOD filed a joint statement of position that they oppose retroactive compensation to Wailuku River Hydro for transformer losses, as proposed by Mauna Kea Power Company, Inc. and the Hawaii Agriculture Research Center. In May 2007, HECO provided the Consumer Advocate, in accordance with Exhibit A of the Updated Stipulation to Resolve Proceeding, authorization to acquire HECO’s specialized version of the production simulation software to enable the Consumer Advocate to perform independent analyses to verify HECO’s results.

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

The utilities are entitled to recover all appropriate and reasonable integrated resource planning and implementation costs, including the costs of DSM programs, either through a surcharge or through their base rates. Under procedural schedules for the IRP cost proceedings, the utilities have been able to recover their incremental IRP costs in the month following the filing of their actual costs incurred for the year, subject to refund with interest pending the PUC’s final D&O approving recovery in the docket for each year’s costs. HELCO (since February 2001) and HECO (since September 2005) recover IRP costs (which are included in O&M) through base rates and MECO continues to recover its costs through a surcharge (as did HELCO and HECO prior to those dates). The Consumer Advocate has objected to the recovery of $2.9 million (before interest) of the $9.0 million of incremental IRP costs incurred by the utilities during the 1997-2006 period, and the PUC’s decision is pending on these costs. Also, see Note 5 in HECO’s “Notes to Consolidated Financial Statements” and “Demand-side management programs” above.

HECO’s IRP. In October 2005, HECO filed its third IRP (IRP-3), which proposes multiple solutions to meet Oahu’s future energy needs, including renewable energy resources, energy efficiency, conservation, technology (such as CHP and DG) and central station generation (including a combustion turbine generating unit in 2009 described under “HECO’s 2009 Campbell Industrial Park (CIP) generating unit”). In addition, HECO currently plans for all existing generating units to remain in operation (future environmental considerations permitting) beyond the 20-year IRP planning period (2006-2025). On March 7, 2007, HECO, the Consumer Advocate and an environmental organization that had been permitted to intervene, filed a stipulation with the PUC, which the PUC approved in its D&O issued on March 21, 2007. The D&O required HECO to (1) file its Evaluation Report for IRP-3 by May 31, 2007, after which the IRP-3 docket will be closed, (2) initiate the development of its IRP-4, beginning with the first Advisory Group meeting in March 2007 and (3) file its IRP-4 Plan and Action Plans by June 30, 2008, unless ordered otherwise by the PUC. On March 29, 2007, the PUC opened a new docket for the IRP-4 plan and, pursuant to the stipulation, the first Advisory Group meeting was held on March 30, 2007. Numerous Advisory Group meetings and technical sessions have been held since then. HECO filed its Evaluation Report for IRP-3 on May 31, 2007. The updated IRP-3 plan continues to include multiple solutions to meet Oahu’s future energy needs. The evaluation report expresses a strong preference for renewable energy. HECO anticipates that the firm capacity currently expected to be needed in 2022, which will be re-evaluated in IRP-4, will be met by a renewable firm capacity resource or resources.

HELCO’s IRP. In May 2007, HELCO filed its third IRP, which proposes multiple solutions to meet future energy needs on the island of Hawaii. The plan includes the installation of a nominal 16 MW steam turbine (ST-7) in 2009 at its Keahole Generating Station (see “HELCO power situation” in Note 5 of HECO’s “Notes to Consolidated Financial Statements”). The plan also follows through on a commitment to have no new fossil-fired generation installed after ST-7. The plan anticipates increasing customer photovoltaic systems plus a 37 gigawatthours per year renewable energy resource in the 2014 to 2020 timeframe, a firm capacity renewable energy resource in 2022, energy efficiency (continuation of existing DSM programs) and CHP. The parties to the IRP-3 proceedings include HELCO, the Consumer Advocate, an environmental organization and HREA. Hearings on the IRP-3 have been scheduled by the PUC for the week of November 26, 2007.

MECO’s IRP. In April 2007, MECO filed its third IRP, which proposes multiple solutions to meet future energy needs on the islands of Maui, Lanai and Molokai, including renewable energy resources (such as photovoltaics, additional wind, biomass and waste-to-energy), energy efficiency (continuation of existing and addition of new DSM programs), technology (such as CHP and DG) and competitive bidding for generation or blocks of generation for 20 MW in each of 2011 and 2013 and 18 MW in 2024 which, under the utility parallel plan, could be located at its Waena site. The plan also includes approximately 2 MW of additional generation through the year 2026 on each of the islands of Lanai and Molokai. On September 21, 2007, the parties to the IRP-3 proceedings, which includes MECO and the Consumer Advocate, filed a stipulated agreement in which they do not request a hearing, they recommend the PUC approve MECO’s IRP-3, MECO agrees to submit evaluation reports by December 31, 2008 and December 31, 2009, MECO agrees to make various improvements to the IRP process and submit its IRP-4 by December 31, 2010, and allowance is made for disposition of this proceeding.

The PPA between MECO and Hawaiian Commercial & Sugar Company (HC&S), which provides for 16 MW of firm capacity, continues in effect from year to year, subject to termination on not less than two years’ prior written notice by either party. In July 2007, however, the parties agreed to not issue a notice of termination that would result in the termination of the PPA prior to the end of 2014. As a result of this agreement with HC&S, for planning purposes it appears that the timing of the need for the second 20 MW block of firm capacity at the Waena site can be deferred from 2013 to the 2015 timeframe. However, identifying the timing of the need for the second 20 MW block of firm capacity in the 2015 timeframe does not reduce MECO’s need to proceed expeditiously with the issuance of an RFP for this second capacity increment, given the multitude of factors that can impact the timing of system firm capacity needs and the potentially long lead time to acquire such resources.

HECO’s 2009 Campbell Industrial Park (CIP) generating unit. HECO plans to build a new 110 MW simple cycle combustion turbine (CT) generating unit at CIP and to add an additional 138 kilovolt transmission line to transmit power from generating units at CIP (including the new unit) to the rest of the Oahu electric grid (collectively, the Project). Plans are for the CT to be run primarily as a “peaking” unit beginning in 2009, fueled by biodiesel, but with the capability of using diesel or naphtha. On December 15, 2005, HECO signed a contract with Siemens to purchase a 110 MW CT unit.

HECO’s Final Environmental Impact Statement for the Project was accepted by the Department of Planning & Permitting of the City and County of Honolulu in August 2006. In May 2007, the Hawaii Department of Health issued the final air permit, which became effective at the end of June 2007. In December 2006, HECO filed with the PUC an agreement with the Consumer Advocate in which HECO committed to use 100% biofuels in its new plant and to take the steps necessary for HECO to reach that goal. In May 2007, the PUC issued a D&O approving the Project. The D&O further stated that no part of the Project costs may be included in HECO’s rate base unless and until the Project is in fact installed, and is used and useful for public utility purposes.

Costs for the Project (exclusive of the costs of the community benefit measures described below) are preliminarily estimated at $164 million. As of September 30, 2007, accumulated Project costs for planning, engineering, permitting, materials, land and AFUDC amounted to $12.3 million.

In August 2007, HECO entered into a contract with Imperium Services, LLC, to supply biodiesel for the planned generating unit, subject to PUC approval. In October 2007, HECO filed an application with the PUC for approval of this biodiesel supply contract.

In a related application filed with the PUC in June 2005, HECO requested approval of community benefit measures to mitigate the impact of the new generating unit on communities near the proposed generating unit site. In June 2007, the PUC issued a D&O which (1) approved HECO’s request to commit funds for HECO’s project to use recycled instead of potable water for industrial water consumption at the Kahe power plant, (2) approved HECO’s request to commit funds for the environmental monitoring programs and (3) denied HECO’s request to provide a base electric rate discount for HECO’s residential customers who live near the proposed generation site. The approved measures are estimated to cost $9 million (through the first 10 years of implementation).

Adequacy of supply.

HECO. HECO’s 2007 Adequacy of Supply (AOS) letter, filed in February 2007, indicates that HECO’s analysis estimates its reserve capacity shortfall to be approximately 70 MW in the 2007 to 2008 period (before the addition of the Campbell Industrial Park combustion turbine planned to be installed in 2009). The availability rates for HECO units have generally declined since 2002 and, based on this experience, the manner in which the units must be operated when there is a reserve capacity shortfall, and the increasing ages of the units, HECO expects availability rates to remain suppressed in the near-term. Although the availability rates for generating units on Oahu continue to be better than those of comparable units on the U.S. mainland, HECO generating units may continue to be entirely or partially unavailable to serve load during scheduled overhaul periods and other planned maintenance outages, or when they “trip” or are taken out of operation or their output is “de-rated” due to equipment failure or other causes.

To mitigate the projected reserve capacity shortfalls, HECO has implemented and is continuing to plan and implement mitigation measures, such as installing distributed generators at substations or other sites, implementing additional load management and other demand reduction measures, and pursuing efforts to improve the availability of generating units. HECO will operate at lower than desired reliability levels and take steps to mitigate the reserve capacity shortfall situation until the next generating unit is installed. Until sufficient generating capacity can be added to the system, HECO will experience a higher risk of generation-related customer outages.

After the planned 2009 addition of the Campbell Industrial Park generating unit, and in recognition of the uncertainty underlying key forecasts, HECO anticipates the potential for continued reserve capacity shortfalls could range between 20 MW to 110 MW in the 2009 to 2012 period, and may seek a firm, dispatchable resource (with a strong preference for a renewable resource) to meet this need, while continuing contingency planning activities. Any plan to install additional firm capacity is required to proceed under the guidance of the Competitive Bidding Framework issued by the PUC in December 2006.

HECO’s gross peak demand was 1,327 MW in 2004, 1,273 MW in 2005, 1,315 MW in 2006 and 1,253 MW in the first ten months of 2007. Peak demand may vary from year to year, but over time, demand for electricity on Oahu is projected to increase. On occasions in 2004, 2005, 2006 and 2007, HECO issued public requests that its customers voluntarily conserve electricity as generating units were out for scheduled maintenance or were unexpectedly unavailable. In addition to making the requests, in 2005, 2006 and 2007, HECO on occasion remotely turned off water heaters for a number of residential customers who participate in its load-control program.

HELCO. HELCO’s 2007 Adequacy of Supply letter filed in January 2007 indicated that HELCO’s generation capacity for the next three years, 2007 through 2009, is sufficiently large to meet all reasonably expected demands for service and provide reasonable reserves for emergencies.

MECO. In December 2005, MECO’s Maalaea Unit 13, a 12.34 MW diesel generator, suffered an equipment failure. In February 2007, MECO filed its 2007 Adequacy of Supply letter, which indicated that MECO’s Maui island system should usually have sufficient installed capacity to meet the forecasted loads once Maalaea Unit 13 returns to service. In July 2007, Maalaea Unit 13 was returned to service.

In April and August 2006 and June and August 2007, MECO experienced lower than normal generation capacity due to the unexpected temporary loss of several of its generating units, and issued public requests that its customers voluntarily conserve electricity.

2006 outages. On June 1, 2006, due to the unanticipated loss of three generating units from an IPP and two HECO generating units, HECO shed power to 29,300 customers in various parts of the island. Power was restored to all customers within four hours.

On Sunday, October 15, 2006, shortly after 7 a.m., two earthquakes centered on the island of Hawaii with magnitudes of 6.7 and 6.0 triggered power outages throughout most of the state and disrupted air traffic on all major islands. On Oahu, following the impact of the earthquakes, a series of protective actions and automatic systems operated to successively shut down all generators to protect them from potential damage. As a result, no significant damage to any of HECO’s generators, or to its transmission and distribution systems, occurred. Following the island-wide outage, HECO restored power to customers in a careful, methodical manner to further protect its system, and as a result power was restored to over 99% of its customers within a period of time ranging from approximately 4¹/2 to 18 hours. Management believes the shutdown and methodical restoration of power were necessary to prevent severe damage to HECO’s generating equipment and power grid and to avoid a more prolonged blackout. HELCO’s and MECO’s smaller electric systems also experienced sustained outages from the earthquakes; however, their systems were, for the most part, back online by mid to late afternoon.

As is the electric utilities’ practice with all major system emergencies, management immediately committed to investigating the outage caused by the earthquakes, including bringing in an outside industry expert to help identify any potential improvements to procedures or systems, and also made arrangements for a preliminary briefing of the PUC. The PUC briefings took place on October 19 and 20, 2006. HECO also conducted a public briefing on October 23, 2006. HECO has made it clear that in addition to any investigation it undertakes, it will cooperate fully with any other reviews conducted by its regulators.

Following requests by members of a state Senate energy subcommittee and the Consumer Advocate that the PUC investigate the power failure, to which investigation HECO stated it did not object, the PUC issued an order on October 27, 2006 opening an investigative proceeding on the outages at HECO, HELCO and MECO. The questions the PUC asked to be addressed in the proceeding include (1) aside from the earthquake, are there any underlying causes that contributed or may have contributed to the power outages, (2) were the actions of the electric utilities prior to and during the power outages reasonable and in the public interest, and were the power restoration processes and communication regarding the outages reasonable and timely under the circumstances, (3) could the island-wide power outages on Oahu and Maui have been avoided, and what are the necessary steps to minimize and improve the response to such occurrences in the future, and (4) what penalties, if any, should be imposed on the electric utilities. Pursuant to the PUC’s order, HECO’s 2006 Outage Report was filed in December 2006, and the outage reports of HELCO and MECO were filed in March 2007. The investigation consultants retained by HECO, POWER Engineers, Inc., concluded that, “HECO’s performance prior to and during the outage demonstrated reasonable actions in the public interest” in a “distinctly extraordinary event.” Power Engineers, Inc. also concluded that HELCO and MECO personnel responded in a “reasonable, responsible, and professional manner.” The consultants also made a number of recommendations, mostly of a technical nature, regarding the operation of the electric system during such an incident. The Consumer Advocate submitted its findings in August 2007 and found the activities and performance of HECO, HELCO and MECO personnel prior to and during the outages were reasonable and in the public interest, and recommended no penalties for “these uncommon power outages.” The Consumer Advocate also made several recommendations regarding training and potential electric system modifications. In October 2007, the electric utilities filed a final statement of position, which included proposed plans to address recommendations made by both POWER Engineers, Inc. and the Consumer Advocate. The docket is awaiting a decision by the PUC.

Management cannot predict the outcome of the investigation or its impacts on the utilities. Management currently believes the financial impacts of property damage and claims resulting from the earthquakes and outages are not material, but future findings and developments may change that belief.

Intra-governmental wheeling of electricity. In June 2007, the PUC initiated an investigation to examine the feasibility of implementing intra-governmental wheeling of electricity in the State of Hawaii. Preliminary issues of the investigation identified by the PUC include (1) identifying what impact, if any, wheeling will have on Hawaii’s electric industry, (2) addressing interconnection matters, (3) identifying the costs to utilities, (4) identifying any rate design and cost allocation issues, (5) considering the financial cost and impact on non-wheeling customers, (6) identifying any power back-up issues and (7) addressing how rates would be set. Parties to this proceeding include HECO, HELCO, MECO, Kauai Island Utility Cooperative and the Consumer Advocate, as well as governmental agencies (the Department of Defense, the City and County of Honolulu and the Counties of Hawaii, Maui and Kauai), two environmental groups, and two renewable energy developers. Two renewable energy contractors and a renewable energy developer also have been granted more limited participant status.

Collective bargaining agreements

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

Legislation and regulation

Congress and the Hawaii legislature periodically consider legislation that could have positive or negative effects on the utilities and their customers.

Energy Policy Act of 2005. On August 8, 2005, the President signed into law the Energy Policy Act of 2005 (the Act). The Act provides $14.5 billion in tax incentives over a 10-year period designed to boost conservation efforts, increase domestic energy production and expand the use of alternative energy sources, such as solar, wind, ethanol, biomass, hydropower and clean coal technology. Ocean energy sources, including wave power, are identified as renewable technologies. Section 355 of the Act authorizes a study by the U.S. Department of Energy of Hawaii’s dependence on oil; however, that provision is subject to appropriation, as is $9 million authorized under Section 208 for a sugar cane ethanol program in Hawaii. Incentives also include tax credits and shorter depreciable lives for many assets associated with energy production and transmission. The Act’s primary direct impact on HECO and its subsidiaries is currently expected to be the reduction in the depreciable tax life, from 20 years to 15 years, of certain electric transmission equipment placed into service after April 11, 2005.

Renewable Portfolio Standard. The 2004 Hawaii Legislature amended an existing renewable portfolio standard (RPS) law to require electric utilities to meet a renewable portfolio standard of 8% of KWH sales by December 31, 2005, 10% by December 31, 2010, 15% by December 31, 2015, and 20% by December 31, 2020. These standards may be met by the electric utilities on an aggregated basis and were met in 2005 when they attained a RPS of 11.7%. It may be difficult, however, for the electric utilities to attain the required renewables percentages in the future, and management cannot predict the future consequences of failure to do so (including potential penalties to be established by the PUC).

The RPS law was further amended in 2006 to provide that at least 50% of the RPS targets must be met by electrical energy generated using renewable energy sources, such as wind or solar, versus from the electrical energy savings from renewable energy displacement technologies (such as solar water heating) or from energy efficiency and conservation programs. The amendment also added provisions for penalties to be established by the PUC if the RPS requirements are not met and criteria for waiver of the penalties by the PUC, if the requirements cannot be met due to circumstances beyond the electric utility’s control.

The PUC must, by December 31, 2007, develop and implement a utility ratemaking structure, which may include, but is not limited to, performance-based ratemaking (PBR), to provide incentives that encourage Hawaii’s electric utility companies to use cost-effective renewable energy resources found in Hawaii to meet the RPS, while allowing for deviation from the standards in the event that the standards cannot be met in a cost-effective manner, or as a result of circumstances beyond the control of the utility which could not have been reasonably anticipated or ameliorated.

On January 11, 2007, the PUC opened a new docket (RPS Docket) to examine Hawaii’s amended RPS law, to establish the appropriate penalties and to determine circumstances under which penalties should be levied. The PUC indicated that the 2006 amendment to the RPS law that added provisions for penalties effectively gives utilities incentive to comply with RPS and therefore the PUC will no longer complete the rulemaking in a process initiated in November 2004, but will instead proceed by way of this RPS Docket to handle any issues related to the utilities meeting renewable portfolio standards. The parties to the proceeding include the electric utilities, the Consumer Advocate, an environmental organization and HREA. The PUC set forth the issues for the proceeding to be (1) the appropriate penalty framework to establish under the RPS law for failure to meet the RPS, (2) the appropriate utility ratemaking structure to establish and include in the framework to provide incentives that encourage electric utilities to use cost-effective renewable energy resources while allowing for deviations from the standards in the event the standards cannot be met in a cost-effective manner, or as a result of circumstances beyond the control of the electric utility that could not have been reasonably anticipated or ameliorated and (3) whether the framework should include a provision that provides incentives to encourage utilities to exceed the RPS or to meet their RPS ahead of time or both. The parties filed preliminary position statements in April 2007. In a supplemental filing in July 2007, HECO, HELCO and MECO proposed a Renewable Energy Infrastructure Program, including a Renewable Energy Infrastructure surcharge mechanism, to encourage the funding of renewable energy infrastructure projects. In October 2007, all but one of the parties executed and filed a stipulation for an RPS framework. The framework includes a renewable energy infrastructure program which consists of two components: 1) renewable energy infrastructure projects that facilitate third-party development of renewable energy resources, maintain existing renewable energy resources and/or enhance energy choices for customers, and 2) the creation and implementation of a temporary renewable energy infrastructure surcharge to recover the capital costs, deferred costs for software development and licenses, and/or other relevant costs approved by the PUC. These costs would be removed from the surcharge and included in base rates in the utility’s next rate case. The stipulating parties agreed that the PUC should initiate a follow-up proceeding to expeditiously consider whether the renewable energy infrastructure program with a permanent surcharge mechanism should be included in the RPS framework. The PUC’s deadline to issue a D&O is December 31, 2007. Management cannot predict the outcome of this process.

Also, see “Renewable energy strategy” under “Other developments” below.

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

In 2005, the Legislature again amended the net energy metering law by, among other revisions, authorizing the PUC, by rule or order, to increase the maximum size of the eligible net metered systems and to increase the total rated generating capacity available for net energy metering. In April 2006, the PUC initiated an investigative proceeding on whether the PUC should increase (1) the maximum capacity of eligible customer-generators to more than 50 kw and (2) the total rated generating capacity produced by eligible customer-generators to an amount above 0.5% of an electric utility’s system peak demand. The parties to the proceeding include HECO, HELCO, MECO, Kauai Island Utility Cooperative, a renewable energy organization and a solar vendor organization. In September 2007, the parties filed a stipulated agreement to increase the maximum size of the eligible customer-generators from 50 kw to 100 kw and the system cap from 0.5% to 1.0% of system peak demand and to reserve a certain percentage of the 1.0% system peak demand for generators under 10 kw. The parties also agreed to consider in the IRP process any further increases in the maximum capacity of customer-generators and the system cap. Depending on their magnitude, changes made by the PUC by rule or order could have a negative effect on electric utility sales. Management cannot predict the outcome of the investigative proceeding.

DSM programs. In 2006, the PUC was given the authority, if it deems appropriate, to redirect all or a portion of the funds currently collected by the utilities and included in their revenues through the current utility DSM surcharge into a Public Benefits Fund, for the purpose of supporting customer DSM programs approved by the PUC. In February 2007, the PUC issued a D&O requiring that administration of EE DSM programs be turned over to a non-utility third party administrator in 2009, to be funded through such a public benefits surcharge. See “Demand-side management programs” above for a discussion of the D&O. In September 2007, the PUC initiated an investigative proceeding to select a Public Benefits Fund Administrator and to refine the details of the new market structure for the EE DSM programs.

Non-fossil fuel purchased power contracts. The 2006 Hawaii State legislature passed a measure which required that the PUC establish a methodology that removes or significantly reduces any linkage between the price paid for non-fossil-fuel-generated electricity under future power purchase contracts and the price of fossil fuel, in order to allow utility customers to receive the potential cost savings from non-fossil fuel generation (in connection with the PUC’s determination of just and reasonable rates in purchased power contracts).

Greenhouse gas emissions reduction. In July 2007, Act 234 became law. Act 234 requires a statewide reduction of greenhouse gas (GHG) emissions by January, 1, 2020 to levels at or below the statewide GHG emission levels in 1990. It also establishes a task force, comprised of representatives of state government, business (including the electric utilities), the University of Hawaii and environmental groups, which is charged with preparing a work plan and regulatory approach for “implementing the maximum practically and technically feasible and cost-effective reductions in greenhouse gas emissions from sources or categories of sources of greenhouse gases” to achieve 1990 statewide GHG emission levels. The work plan and regulatory approach, plus any proposed legislation, are due for submission to the legislature prior to the beginning of the 2010 legislative session. By December 31, 2011, the Director of the DOH is required to adopt rules that establish emission limits for specific sources or categories of sources of emissions and provide for reporting and verification of statewide GHG emissions and monitoring and compliance. In addition, the Director is required to adopt rules based on the findings and recommendations of the work plan to the extent feasible to achieve the statewide greenhouse gas emissions limit. The Director is also authorized to adopt rules establishing a schedule of fees to be paid by sources of GRG emissions regulated by the Act. The electric utilities are participating in the Task Force as well as in initiatives aimed at reducing their GHG emissions. Because the full scope of the Task Force report remains to be determined and regulations implementing Act 234 have not yet been promulgated, management cannot predict the impact of Act 234 on the electric utilities and the Company.

On April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts v. EPA, that, contrary to EPA’s position, the EPA has the authority to regulate greenhouse gases under the Clean Air Act. Although it is too early to assess the ultimate impact of the ruling, since the decision there have been reports that comprehensive legislation may be introduced in Congress this term to regulate greenhouse gas emissions.

Renewable energy. The 2007 Hawaii State Legislature passed a measure stating that the PUC may consider the need for increased renewable energy in rendering decisions on utility matters. Due to this measure, it is possible that, if energy from a renewable source were more expensive than energy from fossil fuel, the PUC may still approve the purchase of energy from the renewable source.

Biofuels. The 2007 Hawaii State Legislature passed a measure that has the stated purpose of encouraging further production and use of biofuels in Hawaii, establishes that biofuel processing facilities in Hawaii are a permitted use in designated agricultural districts and establishes a program with the Hawaii Department of Agriculture to encourage the production in Hawaii of energy feedstock (i.e., raw materials for biofuels).

At this time, it is not possible to predict with certainty the impact of any proposed or new legislation.

Other developments

Advanced Meter Infrastructure (AMI). HECO is evaluating the feasibility of utility applications using wireless technologies for two-way communication.

HECO is currently partnering with Sensus Metering Systems to field test an Advanced Metering Infrastructure system that delivers two-way communications to advanced meters, which can enable automated meter reading, time-of-use pricing and conservation options for HECO customers. This pilot includes approximately 3,000 meters, which have been installed for residential and commercial customers. Other utility applications being evaluated include distribution system line monitoring and water heater and air conditioning load control for residential and commercial customers.

Renewable energy strategy. The electric utilities are taking actions intended to protect Hawaii’s island ecology and counter global warming, while continuing to provide reliable power to customers. A three-pronged strategy supports attainment of the State of Hawaii Renewable Portfolio Standards (RPS) and the Hawaii Global Warming Solutions Act of 2007 by: 1) the greening of existing assets, 2) the expansion of renewable energy generation, and 3) the acceleration of energy efficiency and load management programs. Major initiatives are being pursued in each category.

The electric utilities are actively exploring the use of biofuels for all company-owned existing and planned generating units. HECO has committed to using 100% biofuels for its new 110 MW generating unit planned for 2009. HECO is researching the possibility of switching the steam generating units from fuel oil to biofuels, based upon economic and technical feasibility.

In February 2007, BlueEarth Biofuels LLC (BlueEarth) announced plans for a new biodiesel refining plant to be built on the island of Maui by 2009. The biodiesel plant will be owned by BlueEarth Maui Biofuels LLC (BlueEarth Maui), a planned new venture between BlueEarth and Uluwehiokama Biofuels Corp. (UBC), a newly-formed non-regulated subsidiary of HECO. All of UBC’s profits from the project will be directed into a biofuels public trust to be created for the purpose of funding biofuels development in Hawaii. MECO intends to lease to UBC a portion of the land owned by MECO for its future Waena generation station as the site for the biodiesel plant, with lease proceeds to be credited to MECO ratepayers. In addition, MECO is negotiating a fuel purchase contract with BlueEarth Maui for biodiesel to be used in existing diesel-fired units at MECO’s Maalaea plant. Both the lease agreement and biodiesel fuel contract will require PUC approval. Although not required to do so, BlueEarth Maui has also announced plans to prepare an environmental impact study for the project. HECO, working closely with the Natural Resources Defense Council, developed an environmental policy to ensure that the project would procure sustainable palm oil and locally-grown feedstocks.

The electric utilities also support renewable energy through their solar water heating and heat pump programs, and the negotiation and execution of purchased power contracts with non-utility generators using renewable sources (e.g., refuse-fired, geothermal, hydroelectric and wind turbine generating systems). On September 28, 2007, HECO issued a Solicitation of Interest for its planned Renewable Energy Request for Proposals for combined renewable energy projects up to 100 MW on Oahu.

In December 2002, HECO formed an unregulated subsidiary, Renewable Hawaii, Inc. (RHI), with initial approval to invest up to $10 million in selected renewable energy projects. RHI is seeking to stimulate renewable energy initiatives by prospecting for new projects and sites and taking a passive, minority interest in selected third party renewable energy projects. Since 2003, RHI has actively pursued a number of solicited and unsolicited projects, particularly those utilizing wind, landfill gas, and ocean energy. RHI will generally make project investments only after developers secure the necessary approvals and permits and independently execute a PUC-approved PPA with HECO, HELCO or MECO. While RHI has executed some agreements with project developers, no investments have been made to date.

The electric utilities promote research and development in the areas of biofuels, ocean energy, battery storage, electronic shock absorber, and integration of non-firm power into the isolated island electric grids.

Energy efficiency and demand-side management programs for commercial and industrial customers, and residential customers, including load control programs, have resulted in reducing system peak load and contribute to the achievement of the RPS.

Also, see “Renewable Portfolio Standard” under “Legislation and regulation” above.

Commitments and contingencies

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

Recent accounting pronouncements and interpretations

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

FINANCIAL CONDITION

Liquidity and capital resources

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

HECO’s consolidated capital structure (which includes the impact of the sale of the SPRBs on March 27, 2007 and the application of the proceeds thereof (i) to reimburse the utilities for capital expenditures and their use of the reimbursements to paydown short-term borrowings and (ii) to provide a portion of the funds required to refund two series of SPRBs originally issued in 1996) was as follows as of the dates indicated:


(in millions)	September 30, 2007				December 31, 2006
Short-term borrowings	$	30	2	%	$	113	6	%
Long-term debt		873	45			766	41
Preferred stock		34	2			34	2
Common stock equity		992	51			959	51

	$	1,929	100	%	$	1,872	100	%

As of November 1, 2007, the Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HECO securities were as follows:


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

The rating agencies use a combination of qualitative measures (i.e., assessment of business risk that incorporates an analysis of the qualitative factors such as management, competitive positioning, operations, markets and regulation) as well as quantitative measures (e.g., cash flow, debt, interest coverage and liquidity ratios) in determining the ratings of HECO securities. In May 2007, S&P lowered the long-term corporate credit and unsecured debt ratings on HECO, HELCO and MECO to BBB from BBB+ and lifted HECO’s outlook from “negative” to “stable”. S&P’s rating outlook “assesses the potential direction of a long-term credit rating over the intermediate term (typically six months to two years).” S&P stated that the downgrade “is the result of sustained weak bondholder protection parameters compounded by the financial pressure that continuous need for regulatory relief, driven by heightened capital expenditure requirements, is creating for the next few years.”

S&P also ranks business profiles from “1” (excellent) to “10” (vulnerable), and did not change HECO’s business profile rank of “5”.

In December 2006, Moody’s confirmed its issuer ratings and stable outlook for HECO. Moody’s stated, “The rating could be downgraded should weaker than expected regulatory support emerge, including the continuation of regulatory lag, which ultimately causes earnings and sustainable cash flow to suffer.”

HECO utilizes short-term debt, principally commercial paper, to support normal operations and for other temporary requirements. HECO also periodically borrows short-term from HEI for itself and on behalf of HELCO and

MECO, and HECO may borrow from or loan to HELCO and MECO short-term. The intercompany borrowings among the utilities, but not the borrowings from HEI, are eliminated in the consolidation of HECO’s financial statements. As of September 30, 2007, HECO had $7 million of short-term borrowings from MECO and HELCO had $36 million of short-term borrowings from HECO. HECO had an average outstanding balance of commercial paper for the first nine months of 2007 of $62 million and had $30 million of commercial paper outstanding as of September 30, 2007. Management believes that if HECO’s commercial paper ratings were to be downgraded, it may be more difficult for HECO to sell commercial paper under current market conditions.

Effective April 3, 2006, HECO entered into a revolving unsecured credit agreement establishing a line of credit facility of $175 million with a syndicate of eight financial institutions. The agreement expires on March 31, 2011. See Note 10 of HECO’s “Notes to Consolidated Financial Statements” for a description of the $175 million credit facility. As of November 1, 2007, the line was undrawn. In the future, HECO may seek to modify the credit facility in accordance with the expedited approval process approved by the PUC, including to increase the amount of credit available under the agreement, and/or to enter into new lines of credit, as management deems appropriate.

See Note 11 of HECO’s “Notes to Consolidated Financial Statements” for a discussion of the SPRBs issued in March 2007. SPRBs of up to $20 million (for HELCO) and up to $400 million ($260 million for HECO, $115 million for HELCO and $25 million for MECO) may be issued by the Department of Budget and Finance of the State of Hawaii under 2005 and 2007 legislative authorizations prior to the end of June 30, 2010 and June 30, 2012, respectively, to finance the electric utilities’ capital improvement projects.

The PUC must approve issuances of long-term securities for HECO, HELCO and MECO, including notes or debentures issued by the electric utilities in connection with the issuance of SPRBs, taxable unsecured notes or trust preferred securities.

Operating activities provided $128 million in net cash during the first nine months of 2007. Investing activities during the same period used net cash of $117 million primarily for capital expenditures, net of contributions in aid of construction. Financing activities for the same period used net cash of $5 million due to an $83 million net decrease in short-term borrowings, a $12 million decrease in cash overdraft and the payment of $14 million of common and preferred stock dividends, partly offset by a $104 million net increase in long-term debt.

MATERIAL ESTIMATES AND CRITICAL ACCOUNTING POLICIES

The following updates HECO’s disclosures about material estimates and critical accounting policies on pages 90 to 92 of HECO’s 2006 Form 10-K.

A material estimate was revised in the first quarter of 2007 when HELCO and the Consumer Advocate reached a settlement of the issues in the HELCO 2006 rate case proceeding (see “HELCO power situation” in Note 5 of HECO’s “Notes to Consolidated Financial Statements”). Under the settlement, HELCO agreed to write-off a portion of CT-4 and CT-5 costs, resulting in an after-tax charge to net income of approximately $7 million in the first quarter of 2007. If it becomes probable that the PUC, in its final order, will disallow additional costs incurred for CT-4 and CT-5 for ratemaking purposes, HELCO will be required to again revise its CT-4 and CT-5 costs estimated to be recoverable and record an additional write-off. Another material estimate was revised in the third quarter of 2007 when the PUC issued an amended proposed final D&O for HECO’s 2005 test year rate case, which removed HECO’s pension asset from rate base and resulted in a $15 million reserve accrued for the potential refund of a portion of the interim rate increase. Any revenues recognized pursuant to interim D&Os are subject to refund, with interest, if and to the extent they exceed the amounts allowed in final D&Os.

BANK

RESULTS OF OPERATIONS


(in thousands)	Three months ended September 30				% change		Primary reason(s) for significant change
(in thousands)	2007		2006		% change		Primary reason(s) for significant change
Revenues	$	105,507	$	103,338	2		Higher interest income (resulting from higher average balances on loans and other investments and higher yields on other investments, partly offset by lower average balances on investment and mortgage-related securities and lower yields on loans and investment and mortgage-related securities) and higher noninterest income

Operating income		18,547		20,578	(10	)	Lower net interest income and higher provision for loan losses, partly offset by higher noninterest income and slightly lower noninterest expense

Net income		11,731		13,470	(13	)	Lower operating income and higher effective income tax rate

(in thousands)	Nine months ended September 30				% change		Primary reason(s) for significant change
(in thousands)	2007		2006		% change		Primary reason(s) for significant change
Revenues	$	317,493	$	305,898	4		Higher interest income (resulting from higher average balances on loans and other investments and higher yields on earning assets, partly offset by lower average balances on investment and mortgage-related securities) and higher noninterest income

Operating income		56,669		73,752	(23	)	Lower net interest income and higher noninterest expense and provision for loan losses, partly offset by higher noninterest income

Net income		35,909		46,515	(23	)	Lower operating income, partly offset by lower income taxes

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

Net interest margin

Earnings of ASB depend primarily on net interest income, which is the difference between interest earned on earning assets and interest paid on costing liabilities. If the current interest rate environment persists, compression of ASB’s net interest margin will continue to adversely impact earnings.

Loan originations and purchases of loans and mortgage-related securities are ASB’s primary sources of earning assets. ASB’s loan volumes and yields are affected by market interest rates, competition, demand for financing, availability of funds and management’s responses to these factors. As of September 30, 2007, ASB’s loan portfolio mix, net, consisted of 75% residential loans, 11% commercial loans, 7% commercial real estate loans and 7% consumer loans. As of December 31, 2006, ASB’s loan portfolio mix, net, consisted of 72% residential loans, 12% commercial loans, 9% commercial real estate loans and 7% consumer loans. ASB’s mortgage-related securities portfolio consists primarily of shorter-duration assets and is affected by market interest rates and demand.

Deposits continue to be the largest source of funds for ASB and are affected by market interest rates, competition and management’s responses to these factors. Advances from the FHLB of Seattle and securities sold under agreements to repurchase continue to be significant sources of funds. As of September 30, 2007, ASB’s costing liabilities consisted of 72% deposits and 28% other borrowings. As of December 31, 2006, ASB’s costing liabilities consisted of 74% deposits and 26% other borrowings. High short-term interest rates have made it difficult to retain deposits and control funding costs. Deposit retention and growth will remain a challenge in the current environment.

Although higher long-term interest rates could reduce the market value of available-for-sale investment and mortgage-related securities and reduce stockholder’s equity through a balance sheet charge to AOCI, this reduction in the market value of investments and mortgage-related securities would not result in a charge to net income in the absence of a sale of such securities or an “other-than-temporary” impairment in the value of the securities. As of September 30, 2007 and December 31, 2006, the unrealized losses, net of tax benefits, on available-for-sale investments and mortgage-related securities (including securities pledged for repurchase agreements) in AOCI was $25 million and $35 million, respectively. The decrease in unrealized losses was largely due to movement in the general level of interest rates within the third quarter of 2007. See “Quantitative and qualitative disclosures about market risk.”

The following table sets forth average balances, interest and dividend income, interest expense and weighted-average yields earned and rates paid, for certain categories of earning assets and costing liabilities for the three and nine months ended September 30, 2007 and 2006.


($ in millions)	Three months ended September 30							Nine months ended September 30
($ in millions)	2007		2006		Change			2007		2006		Change
Loans receivable
Average balances ¹	$	3,929	$	3,745	$	184		$	3,845	$	3,665	$	180
Interest income ²		62		60		2			182		172		10
Weighted-average yield (%)		6.28		6.33		(0.05	)		6.32		6.26		0.06
Investments and mortgage-related securities
Average balances	$	2,269	$	2,462	$	(193	)	$	2,342	$	2,550	$	(208	)
Interest income		25		27		(2	)		81		87		(6	)
Weighted-average yield (%)		4.45		4.46		(0.01	)		4.60		4.53		0.07
Other investments ³
Average balances	$	183	$	166	$	17		$	198	$	170	$	28
Interest and dividend income		1		1		—			4		2		2
Weighted-average yield (%)		2.68		2.11		0.57			2.87		2.02		0.85
Total earning assets
Average balances	$	6,381	$	6,373	$	8		$	6,385	$	6,385	$	—
Interest and dividend income		88		88		—			267		261		6
Weighted-average yield (%)		5.53		5.50		0.03			5.58		5.46		0.12
Deposit liabilities
Average balances	$	4,397	$	4,531	$	(134	)	$	4,475	$	4,548	$	(73	)
Interest expense		20		20		—			62		52		10
Weighted-average rate (%)		1.84		1.73		0.11			1.85		1.53		0.32
Other borrowings
Average balances	$	1,752	$	1,629	$	123		$	1,678	$	1,629	$	49
Interest expense		20		19		1			57		54		3
Weighted-average rate (%)		4.57		4.59		(0.02	)		4.54		4.45		0.09
Total costing liabilities
Average balances	$	6,149	$	6,160	$	(11	)	$	6,153	$	6,177	$	(24	)
Interest expense		40		39		1			119		106		13
Weighted-average rate (%)		2.62		2.48		0.14			2.58		2.30		0.28
Net average balance	$	232	$	213	$	19		$	232	$	208	$	24
Net interest income		48		49		(1	)		148		155		(7	)
Interest rate spread (%)		2.91		3.02		(0.11	)		3.00		3.16		(0.16	)
Net interest margin (%) ⁴		3.01		3.10		(0.09	)		3.09		3.23		(0.14	)

¹	Includes nonaccrual loans.

²	Includes loan fees of $1.0 million and $1.2 million for the three months and $3.4 million and $4.0 million for the nine months ended September 30, 2007 and 2006, respectively, together with interest accrued prior to suspension of interest accrual on nonaccrual loans.

³	Includes federal funds sold and interest bearing deposits and stock in the FHLB of Seattle ($98 million as of September 30, 2007).

⁴	Defined as net interest income as a percentage of average earning assets.

Results – three months ended September 30, 2007

Net interest income before provision for loan losses for the three months ended September 30, 2007 decreased by $1.5 million, or 3%, when compared to the same period in 2006. ASB continued to increase its loans, but high short-term interest rates have made it difficult to retain deposits and control funding costs and caused ASB to experience further margin compression. Net interest margin was 3.01% in the third quarter of 2007 compared to 3.10% in the third quarter of 2006 as the impact of higher balances of loans and other investments and higher yields on earning assets were more than offset by the impact of lower balances of investment and mortgage-related securities and higher funding costs in the third quarter of 2007 compared to the third quarter of 2006. The increase in the average loan portfolio balance was due, in part, to the continued strength in the Hawaii economy and real estate market and loans purchased. Although new home purchase and home resale transaction volumes have fallen off, prices have remained stable and Hawaii’s residential real estate market has not experienced the declines in values or increase in foreclosures seen in many mainland U.S. markets. Because of this, ASB was fairly well insulated from the deteriorating credit conditions that have impacted many mainland banks during the quarter. The decrease in the average investment and mortgage-related securities portfolios was due to the use of proceeds from repayments in the portfolio to fund loans. Average deposit balances in the third quarter of 2007 decreased by $134.2 million, or 3%, compared to the third quarter of 2006. The shift in deposit mix from lower cost savings and checking accounts to higher cost certificates and other borrowings, along with the repricing of deposits, has contributed to increased funding costs.

During the third quarter of 2007, ASB recorded a $2.7 million provision for loan loss primarily attributable to the same commercial borrower for which ASB provisioned in the second quarter of 2007. The additional loan loss provision, which significantly reduced ASB’s remaining exposure to this borrower, is the result of new developments during the third quarter of 2007 that may impact the collectibility of the commercial loans from this borrower. ASB does not have any lending programs targeted at subprime borrowers. There was no loan loss provision recorded in the third quarter of 2006.

Third quarter of 2007 noninterest income increased by $1.6 million, or 11%, when compared to the third quarter of 2006, primarily due to increases in deposit fees. Noninterest income for the third quarter of 2006 included a $1.7 million gain on sale of securities. There were no similar gains in the third quarter of 2007.

Noninterest expense for the third quarter of 2007 decreased by $0.5 million, or 1%, when compared to the third quarter of 2006.

Results – nine months ended September 30, 2007

Net interest income before provision for loan losses for the nine months ended September 30, 2007 decreased by $6.7 million, or 4%, when compared to the same period in 2006. ASB continued to increase its loans, but the high short-term interest rates have made the interest rate environment significantly more challenging than it was during the first nine months of 2006 and caused ASB to experience further margin compression. Net interest margin was 3.09% in the first nine months of 2007 compared to 3.23% in the first nine months of 2006 as the impact of higher balances of loans and other investments and higher yields on earning assets were more than offset by the impact of lower balances of investment and mortgage-related securities and higher funding costs in the first nine months of 2007 compared to the first nine months of 2006. The increase in the average loan portfolio balance was due, in part, to the continued strength in the Hawaii economy and real estate market and loans purchased. The decrease in the average investment and mortgage-related securities portfolios was due to the use of proceeds from repayments in the portfolio to fund loans. Average deposit balances during the first nine months of 2007 decreased by $73.0 million, or 2%, compared to the first nine months of 2006. The shift in deposit mix from lower cost savings and checking accounts to higher cost certificates and other borrowings, along with the repricing of deposits, has contributed to increased funding costs.

During the first nine months of 2006, the need to provide for loan losses as a result of additional loan growth was fully offset by the release of reserves on existing loans due to strong asset quality. During the first nine months of 2007, ASB recorded a provision for loan losses of $3.9 million primarily due to one commercial borrower, which significantly reduced ASB’s remaining exposure to this borrower. ASB does not have any lending programs targeted at subprime borrowers. As of September 30, 2007, ASB’s allowance for loan losses was 0.88% of average loans outstanding, compared to 0.85% at December 31, 2006 and 0.82% at September 30, 2006. As of September 30, 2007, ASB’s nonperforming assets to total assets was 0.12%, compared to 0.03% and 0.02% as of December 31, 2006 and September 30, 2006, respectively.


Nine months ended September 30	2007		2006
(in thousands)
Allowance for loan losses, January 1	$	31,228	$	30,595
Provision for loan losses		3,900		—
Less: Net charge-offs		1,406		571

Allowance for loan losses, September 30	$	33,722	$	30,024

For the first nine months of 2007, noninterest income increased by $5.5 million, or 12%, when compared to the first nine months of 2006, primarily due to increases in deposit fees.

Noninterest expense for the nine months ended September 30, 2007 increased by $12.1 million, or 10%, when compared to the first nine months of 2006, primarily due to higher legal and other litigation expenses, costs to strengthen ASB’s risk management and compliance infrastructure, which are expected to continue, and higher occupancy expenses.

Regulatory compliance

ASB is subject to a range of bank regulatory compliance obligations. In connection with ASB’s review of internal compliance processes and OTS examinations, certain compliance deficiencies were identified. ASB has and continues to take steps to remediate these deficiencies and to strengthen ASB’s overall compliance programs. ASB understands that the OTS will initiate enforcement action against it as a result of OTS concerns regarding Bank Secrecy Act and other compliance deficiencies which may result in a consensual order directing remediation of such deficiencies. ASB is unable to predict what specific measures the OTS may require it to take, what other actions, if any, may be initiated by the OTS and other governmental authorities against ASB, or the impact of any such measures or actions on ASB or the Company.

FHLB of Seattle business and capital plan

In December 2004, the FHLB of Seattle signed an agreement with its regulator, the Federal Housing Finance Board (Finance Board), to adopt a business and capital plan to strengthen its risk management, capital structure and governance. At the time and as of September 30, 2007, ASB had an investment in FHLB of Seattle stock of $98 million. In January 2007, the FHLB of Seattle announced that the Finance Board had terminated its agreement with the FHLB of Seattle, attributing the termination to its full compliance with the terms of the agreement and significant progress the FHLB of Seattle has made in implementing its business and capital management plan. In May 2007 and August 2007, ASB received a cash dividend of $147,000. Previously, ASB had received a cash dividend of $98,000 in each of February 2007 and December 2006. No dividends were received by ASB from the FHLB of Seattle during the fourth quarter of 2004, the last three quarters of 2005 and the first three quarters of 2006.

FINANCIAL CONDITION

Liquidity and capital resources


(in millions)	September 30, 2007		December 31, 2006		% change
Total assets	$	6,792	$	6,808	—
Available-for-sale investment and mortgage-related securities		2,161		2,367	(9	)
Investment in stock of FHLB of Seattle		98		98	—
Loans receivable, net		4,020		3,780	6
Deposit liabilities		4,387		4,576	(4	)
Other bank borrowings		1,732		1,569	10

As of September 30, 2007, ASB was the third largest financial institution in Hawaii based on assets of $6.8 billion and deposits of $4.4 billion.

In March 2007, Moody’s raised ASB’s counterparty credit rating to A3 from Baa3. In doing so, Moody’s acknowledged ASB’s high capital ratios, excellent asset quality indicators and prudent liquidity posture. In April 2007, S&P raised ASB’s long-term/short-term counterparty credit ratings to BBB/A-2 from BBB-/A-3. In doing so, S&P acknowledged the improvement in ASB’s interest rate risk and funding profiles from its community banking strategy, its still modest credit risk profile and its solid capital base. These ratings are not recommendations to buy, sell or hold any securities; such ratings may be subject to revision or withdrawal at any time by the rating agencies; and each rating should be evaluated independently of any other rating.

As of September 30, 2007, ASB’s unused FHLB borrowing capacity was approximately $1.5 billion. As of September 30, 2007, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.2 billion. Management believes ASB’s current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.

For the first nine months of 2007, net cash provided by ASB’s operating activities was $51 million. Net cash used during the same period by ASB’s investing activities was $24 million, primarily due to purchases of investment and mortgage-related securities of $224 million and a net increase in loans receivable of $240 million, partly offset by repayments of investment and mortgage-related securities of $443 million. Net cash used in financing activities during this period was $63 million, primarily due to a net decrease in deposit liabilities of $188 million and payment of $33 million in common stock dividends, partly offset by net increases in Federal Home Loan Bank advances of $101 million, securities sold under agreements to repurchase of $12 million and retail repurchase agreements of $51 million.

As of September 30, 2007, ASB was well-capitalized (ratio requirements noted in parentheses) with a leverage ratio of 7.8% (5.0%), a Tier-1 risk-based capital ratio of 14.0% (6.0%) and a total risk-based capital ratio of 14.9% (10.0%).

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Company considers interest-rate risk (a non-trading market risk) to be a very significant market risk for ASB as it could potentially have a significant effect on the Company’s financial condition and results of operations. For additional quantitative and qualitative information about the Company’s market risks, see pages 94 to 96 of HEI’s 2006 Form 10-K.

ASB’s interest-rate risk sensitivity measures as of September 30, 2007 and December 31, 2006 constitute “forward-looking statements” and were as follows:


	September 30, 2007						December 31, 2006
	Change in NII		NPV ratio		NPV ratio sensitivity *		Change in NII		NPV ratio		NPV ratio sensitivity *
Change in interest rates (basis points)	Gradual change		Instantaneous change				Gradual change		Instantaneous change
+300	(4.0	)%	6.74	%	(388	)	(3.8	)%	7.83	%	(341	)
+200	(2.6	)	8.14		(248	)	(2.6	)	9.09		(215	)
+100	(1.1	)	9.50		(112	)	(1.3	)	10.29		(95	)
Base	—		10.62		—		—		11.24		—
-100	1.0		11.20		58		2.0		11.64		40
-200	0.2		10.88		26		1.8		11.27		3
-300	(2.4	)	10.06		(56	)	0.3		10.60		(64	)

*	Change from base case in basis points.

ASB’s net interest income sensitivity as of September 30, 2007 generally shows a decrease in sensitivity for small interest rate changes when compared to net interest income sensitivity as of December 31, 2006. The decrease in sensitivity was primarily due to a shift in mix of assets and liabilities between December 31, 2006 and September 30, 2007 (see ASB’s “Consolidated Statements of Income Data” in Note 4 of HEI’s “Notes to Consolidated Financial Statements”).

ASB’s base net portfolio value (NPV) ratio as of September 30, 2007 declined compared to the NPV ratio as of December 31, 2006. The decrease was due to the shift in the mix of assets and liabilities and changes in the level of interest rates.

ASB’s NPV ratio sensitivity measures as of September 30, 2007 generally increased when compared to the NPV ratio sensitivity measures as of December 31, 2006. Changes in the bank’s balance sheet mix increased the duration of assets and decreased the duration of liabilities causing the increase in sensitivity.

The computation of the prospective effects of hypothetical interest rate changes on the net interest income (NII) sensitivity, NPV ratio, and NPV ratio sensitivity analyses is based on numerous assumptions, including relative levels of market interest rates, loan prepayments, balance changes and pricing strategies, and should not be relied upon as indicative of actual results. (See page 95 of HEI’s 2006 Form 10-K for a more detailed description of key modeling assumptions used in the NII sensitivity analysis.) To the extent market conditions and other factors vary from the assumptions used in the simulation analysis, actual results may differ materially from the simulation results. Furthermore, NII sensitivity analysis measures the change in ASB’s twelve-month, pre-tax NII in alternate interest rate scenarios, and is intended to help management identify potential exposures in ASB’s current balance sheet and formulate appropriate strategies for managing interest rate risk. The simulation does not contemplate any actions that ASB management might undertake in response to changes in interest rates. Further, the changes in NII vary in the twelve-month simulation period and are not necessarily evenly distributed over the period. These analyses are for analytical purposes only and do not represent management’s views of future market movements, the level of future earnings, or the timing of any changes in earnings within the twelve month analysis horizon. The actual impact of changes in interest rates on NII will depend on the magnitude and speed with which rates change, actual changes in ASB’s balance sheet, and management’s responses to the changes in interest rates.

Item 4. Controls and Procedures

HEI:

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Constance H. Lau, HEI Chief Executive Officer, and Eric K. Yeaman, HEI Chief Financial Officer, have evaluated the disclosure controls and procedures of HEI as of September 30, 2007. Based on their evaluations, as of September 30, 2007, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective in ensuring that information required to be disclosed by HEI in reports HEI files or submits under the Securities Exchange Act of 1934:

(1)

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

(2)

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

Internal Control Over Financial Reporting

During the third quarter of 2007, there has been no change in internal control over financial reporting identified in connection with management’s evaluation of the effectiveness of the Company’s internal control over financial reporting as of September 30, 2007 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

HECO:

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

T. Michael May, HECO Chief Executive Officer, and Tayne S. Y. Sekimura, HECO Chief Financial Officer, have evaluated the disclosure controls and procedures of HECO as of September 30, 2007. Based on their evaluations, as of September 30, 2007, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective in ensuring that information required to be disclosed by HECO in reports HECO files or submits under the Securities Exchange Act of 1934:

(1)

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

(2)

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

Internal Control Over Financial Reporting

During the third quarter of 2007, there has been no change in internal control over financial reporting identified in connection with management’s evaluation of the effectiveness of HECO and its subsidiaries’ internal control over financial reporting as of September 30, 2007 that has materially affected, or is reasonably likely to materially affect, HECO and its subsidiaries’ internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

The descriptions of legal proceedings (including judicial proceedings and proceedings before the PUC and environmental and other administrative agencies) in HEI’s Form 10-K (see “Part II. Item 1. Legal Proceedings”) and this 10-Q (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and HECO’s “Notes to Consolidated Financial Statements”) are incorporated by reference in this Item 1. With regard to any pending legal proceeding, alternative dispute resolution, such as mediation or settlement, may be pursued where appropriate, with such efforts typically maintained in confidence unless and until a resolution is achieved. Certain HEI subsidiaries (including HECO and its subsidiaries and ASB) may also be involved in ordinary routine PUC proceedings, environmental proceedings and litigation incidental to their respective businesses.

Item 1A. Risk Factors

For information about Risk Factors, see pages 33 to 42 of HEI’s 2006 Form 10-K, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Quantitative and Qualitative Disclosures about Market Risk,” HEI’s Consolidated Financial Statements and HECO’s Consolidated Financial Statements herein. Also, see “Forward-Looking Statements” on page v of HEI’s 2006 Form 10-K, as updated on page iv herein.

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

(a) For the nine months ended September 30, 2007, HEI issued an aggregate of 32,600 shares of unregistered common stock pursuant to the HEI 1990 Nonemployee Director Stock Plan, as amended and restated effective June 12, 2007 (the HEI Nonemployee Director Plan). Under the HEI Nonemployee Director Plan, each HEI nonemployee director receives, in addition to an annual cash retainer, an annual stock grant of 1,800 shares of HEI common stock (2,000 shares for the first time grant to a new HEI director) and each nonemployee subsidiary director who is not also an HEI nonemployee director receives an annual stock grant of 1,000 shares of HEI common stock (1,000 shares for the first time grant to a new subsidiary director). The HEI Nonemployee Director Plan is currently the only plan for nonemployee directors and provides for annual stock grants (described above) and annual cash retainers for nonemployee directors of HEI and its subsidiaries.

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

Item 5. Other Information

A. Ratio of earnings to fixed charges.


	Nine months ended September 30		Years ended December 31
	2007	2006	2006	2005	2004	2003	2002
HEI and Subsidiaries
Excluding interest on ASB deposits	1.53	2.23	2.08	2.31	2.32	2.11	2.03
Including interest on ASB deposits	1.35	1.85	1.73	1.98	2.00	1.84	1.72
HECO and Subsidiaries	1.84	3.36	3.14	3.23	3.49	3.36	3.71

See HEI Exhibit 12.1 and HECO Exhibit 12.2.

B. News release.

On November 1, 2007, HEI issued a news release, “Hawaiian Electric Industries, Inc. Reports Third Quarter 2007 Earnings.” See HEI Exhibit 99.1.

C. Expiration of HEI Rights Agreement.

HEI and Continental Stock Transfer & Trust Company, as Rights Agent, entered into a Rights Agreement, dated October 28, 1997, which was subsequently amended on May 7, 2003 and October 26, 2004. At its meeting on October 30, 2007, the HEI Board unanimously voted to allow the Rights Agreement to expire in accordance with its terms on November 1, 2007 and the Rights Agreement and related rights created thereby have expired. At the time the Rights Agreement was entered into and in accordance with its provisions, the Board authorized a series of 500,000 shares of Preferred Stock designated as Series A Junior Preferred Stock and filed a resolution establishing the terms of this series of preferred stock with the Hawaii Department of Commerce and Consumer Affairs. No shares of Series A Junior Preferred Stock were ever issued pursuant to the Rights Agreement and, with expiration of the Rights Agreement, none are planned to be issued. Because the resolution establishing the terms of the Series A Junior Preferred Stock is considered part of HEI’s Articles of Incorporation, however, elimination of this series of preferred stock will require shareholder approval of an amendment to the Articles.

Since the Rights Agreement has expired, the legend under the heading “Important Additional Information” regarding certain rights under the Rights Agreement printed on certain outstanding advices and certificates is no longer applicable.

D. HEI’s and HECO’s Amended and Restated By-Laws.

In October 2007, the HEI and HECO Boards of Directors approved amendments to the By-Laws of the Company and HECO, respectively, primarily to conform text to State statutes and update information.

The By-Laws, amended and restated in their entireties to incorporate these amendments, are included as HEI Exhibit 3(ii).1 and HECO Exhibit 3(ii).2 to this Form 10-Q.

E. Change of medium-term note (MTN) trustee

Effective November 1, 2007, CITIBANK, N.A. resigned as trustee and U.S. Bank National Association was appointed as the successor trustee for HEI’s MTNs. The agreement providing for the resignation of CITIBANK, N.A, as trustee, and the substitution of U.S. Bank National Association, as substitute trustee, is included as HEI Exhibit 99.2 to the Form 10-Q.

F. Description of HEI capital stock.

The following updates and restates the description of the Common Stock and Preferred Stock of Hawaiian Electric Industries, Inc. (“HEI”), and other related matters, for the purpose of updating the description thereof in registration statements filed by HEI under the Securities Exchange Act of 1934, as amended, and the Securities Act of 1933, as amended. The principal development requiring this updating is the termination on November 1, 2007, in accordance with its terms, of the Rights Plan adopted by the Board of Directors of HEI on October 28, 1997, as subsequently amended.

Description of Capital Stock

Under HEI’s Restated Articles of Incorporation, as amended, HEI is authorized to issue 200,000,000 shares of Common Stock without par value and 10,000,000 shares of Preferred Stock without par value. The HEI Board of Directors (the “Board”) has authorized and designated only one series of Preferred Stock, being 500,000 shares of Series A Junior Participating Preferred Stock, none of which has been issued and, with the expiration of the Rights Plan, none is expected to be issued. The following description of the terms of HEI’s capital stock sets forth the general terms and provisions of HEI’s capital stock as of the date hereof, and does not purport to be complete. This description is subject to and qualified in its entirety by reference to HEI’s Restated Articles of Incorporation, as amended and the resolution of the HEI Board of Directors creating and fixing the terms of the Series A Junior Participating Preferred Stock.

General

The outstanding shares of HEI’s Common Stock, other than shares of restricted stock issued from time to time under HEI’s Stock Option and Incentive Plan of 1987, as amended, until such restrictions are satisfied, are fully paid and nonassessable. Additional shares of Common Stock, when issued, will be fully paid and nonassessable when the

consideration for which HEI’s Board of Directors authorizes their issuance has been received by HEI. The holders of Common Stock have no preemptive rights and there are no applicable conversion, redemption or sinking fund provisions.

HEI’s Common Stock is transferable at the Shareholder Services Office of HEI, American Savings Bank Tower, 8^th Floor, 1001 Bishop Street, Honolulu, Hawaii 96813, and at the office of Continental Stock Transfer & Trust Company, Co-Transfer Agent and Registrar, 17 Battery Place, New York, New York 10004.

Common Stock

Dividend Rights and Limitations

Stock and cash dividends may be paid to the holders of Common Stock as and when declared by the HEI Board of Directors, provided that, after giving effect thereto, HEI is able to pay its debts as they become due in the usual course of its business and HEI’s total assets are not less than the sum of its total liabilities plus the maximum amount that would be payable in any liquidation in respect of all outstanding shares having preferential rights in liquidation. All shares of Common Stock are entitled to participate equally with respect to dividends.

HEI is a legal entity separate and distinct from its various subsidiaries. As a holding company with no significant operations of its own, the principal sources of its funds are dividends or other distributions from its operating subsidiaries, borrowings and sales of equity. The ability of certain of HEI’s direct and indirect subsidiaries to pay dividends or make other distributions to HEI, or to make loans or extend credit to or purchase assets from HEI, is subject to contractual, statutory and regulatory restrictions, including without limitation the provisions of an agreement with the Public Utilities Commission of the State of Hawaii (“PUC”) (pertaining to HEI’s electric public utility subsidiaries) and the minimum capital requirements imposed by law on HEI’s federal savings bank subsidiary, as well as restrictions and limitations set forth in debt instruments, preferred stock resolutions and guarantees. HEI does not expect that the regulatory and contractual restrictions applicable to HEI or its direct or indirect subsidiaries will significantly affect its ability to pay dividends on its Common Stock. Please see “Business—Regulation and other matters—Restrictions on dividends and other distributions” in HEI’s Annual Report on Form 10-K for the year ended December 31, 2006 for a more complete description of the ability of certain of HEI’s subsidiaries to pay dividends or make other distributions to HEI.

Liquidation Rights

In the event of any liquidation, dissolution, receivership, bankruptcy or winding up of the affairs of HEI, voluntarily or involuntarily, holders of HEI’s Common Stock are entitled to any assets of HEI available for distribution to HEI’s shareholders after the payment in full of any preferential or other amounts to which holders of any Preferred Stock may be entitled. All shares of Common Stock will rank equally in the event of liquidation.

Voting Rights

Holders of Common Stock are entitled to one vote per share, subject to such limitation or loss of right as may be provided in resolutions which may be adopted from time to time creating series of Preferred Stock or otherwise. At annual and special meetings of shareholders, a majority of the outstanding shares of Common Stock constitute a quorum and any action may be approved if a quorum is present and the votes cast in favor of the action exceed the votes cast opposing the action, except (a) as otherwise required by law, (b) with respect to the amendment of certain provisions of HEI’s By-laws and (c) as may be provided in resolutions that may be adopted from time to time creating series of Preferred Stock or otherwise.

Under HEI’s current By-laws, one-third (as nearly as possible) of the total number of directors is elected at each annual meeting of shareholders and no holder of Common Stock is entitled to cumulate votes in an election of directors so long as HEI shall have a class of securities registered pursuant to the Exchange Act that is listed on a national securities exchange or traded over-the-counter on the National Association of Securities Dealers, Inc. Automated Quotation System. If a quorum is present at a meeting at which directors are to be elected, directors are

elected by a plurality of the votes cast in the election. Under HEI’s current By-laws, directors may be removed from office only for cause.

An amendment to the provisions in the By-laws relating to (1) matters which may be brought before an annual meeting, (2) matters which may be brought before a special meeting, (3) cumulative voting, (4) the number and staggered terms of, and the manner of nominating, members of the Board, (5) removal of directors and (6) amendment of certain provisions of the By-laws must in each case be approved either (a) by the affirmative vote of 80% of the shares entitled to vote generally with respect to election of directors voting together as a single class, or (b) by the affirmative vote of a majority of the entire Board plus a concurring vote of a majority of the “continuing directors” (as that term is defined in the By-laws) voting separately and as a subclass of directors.

The provisions of HEI’s By-laws discussed in the foregoing two paragraphs, and the statutory provisions discussed below, may have the effect of delaying, deferring or preventing a change in control of HEI.

Preferred Stock

General

Preferred Stock may be authorized by the Board for issuance in one or more series, without action by HEI’s shareholders and with such preferences, voting powers, restrictions and qualifications as may be fixed by resolution of the Board authorizing the issuance of those shares. Under current Hawaii law, all shares of a series of preferred stock must have preferences, limitations and relative rights identical with those of other shares of the same series and, except to the extent otherwise provided in the description of the series, with those of other series in the same class.

If and when authorized by the Board, Preferred Stock may be preferred as to dividends or in liquidation, or both, over the Common Stock. For example, the terms of the Preferred Stock, if and when authorized, could prohibit dividends on shares of Common Stock until all dividends and any mandatory redemptions have been paid with respect to shares of Preferred Stock. In addition, the Board may, without shareholder approval, issue Preferred Stock with voting and conversion rights which could adversely affect the voting power or economic rights of the holders of Common Stock. Issuance of Preferred Stock by HEI could thus have the effect of delaying, deferring or preventing a change of control of HEI. The first and only series of Preferred Stock that has been authorized by the Board as of the date hereof is the Series A Junior Participating Preferred Stock that was created in connection with the establishment of HEI’s Shareholder Rights Plan, none of which Preferred Stock has been issued. Since the Rights Plan has now terminated, it is not contemplated that any shares of the Series A Junior Participating Preferred Stock will be issued.

Principal Terms of the Series A Junior Participating Preferred Stock

On October 28, 1997, the Board of Directors of HEI authorized a series of 500,000 shares of Preferred Stock, designated the Series A Junior Participating Preferred Stock. The Series A Junior Participating Preferred Stock is without par value, and was created in conjunction with the Board’s adoption of the Rights Agreement. The Series A Junior Participating Preferred Stock was created to be available for purchase under certain circumstances, as set forth in the Rights Agreement. The exercise price for one one-hundredth of a share of Series A Junior Participating Preferred Stock is $112, subject to adjustment.

The Series A Junior Participating Preferred Stock ranks junior to all other series of Preferred Stock as to the payment of dividends and distribution of assets, unless the terms of any such series provide otherwise. If declared by the Board of Directors out of funds legally available therefore, the dividend rate for the Series A Junior Participating Preferred Stock is the greater of $61.00 per quarter, or 200 times the then current quarterly dividend per share of Common Stock (as adjusted for the 2004 Stock Split and subject to future adjustment from time to time to reflect stock dividends, subdivisions or combinations). Whenever quarterly dividends on the Series A Junior Participating Preferred Stock are in arrears, dividends or other distributions may not be made on the Common Stock or on any series of Preferred Stock ranking junior to the Series A Junior Participating Stock. Upon liquidation, no holders of shares ranking junior to the Series A Junior Participating Preferred Stock shall receive any distribution until all holders of the Series A Junior Participating Preferred Stock shall have received $100 per share, plus any unpaid dividends

(the “Series A Liquidation Preference”). Following payment of the Series A Liquidation Preference, no additional distributions shall be made to the holders of Series A Junior Participating Preferred Stock unless holders of Common Stock receive an amount equal to the Series A Liquidation Preference divided by 200 and thereafter (and after taking into account any amounts that may then be due to holders of any other series of Preferred Stock) the holders of the Series A Junior Participating Preferred Stock shall be entitled to share in the remaining assets of HEI with the holders of the Common Stock, ratably on a per share basis in the ratio of 200 to 1 with respect to Preferred Stock and Common Stock. In the event that there are not sufficient assets available to permit payment in full of the Series A Liquidation Preference and the liquidation preferences of all other series of Preferred Stock, if any, which rank on a parity with the Series A Junior Participating Stock, then such remaining assets shall be distributed ratably to the holders of such parity shares in proportion to their respective liquidation preferences.

Each share of Series A Junior Participating Preferred Stock shall entitle the holder thereof to 200 votes (as adjusted for the 2004 Stock Split and subject to future adjustment) on all matters submitted to a vote of the shareholders of HEI, voting together with the Common Stock. If dividends on any Series A Junior Participating Preferred Stock are in arrears in an amount equal to six quarterly dividends, then until dividends for all previous quarters and for the current quarter have been declared and paid or set aside for payment, the holders of Series A Junior Participating Preferred Stock, voting as a class with holders of other series of Preferred Stock who are then entitled to vote thereon, shall also have the right to elect two directors to HEI’s Board. The shares of Series A Junior Participating Preferred Stock are not redeemable.

Restriction on Purchases of Shares and Consequences of Substantial Holdings of Shares under Certain Hawaii and Federal Laws

Provisions of Hawaii and federal law, some of which are described below, place restrictions on the acquisition of beneficial ownership of 5% or more of the voting power of HEI. The following does not purport to be a complete enumeration of all of these provisions, nor does it purport to be a complete description of the statutory provisions that are enumerated. Persons contemplating the acquisition of 5% or more of the issued and outstanding shares of HEI’s Common Stock should consult with their legal and financial advisors concerning statutory and other restrictions on such acquisitions.

The Hawaii Control Share Acquisition Act places restrictions on the acquisition of ranges of voting power (starting at 10% and at 10% intervals up to a majority) for the election of directors of HEI unless the acquiring person obtains approval of the acquisition, in the manner specified in the Control Share Acquisition Act, by the affirmative vote of the holders of a majority of the voting power of all shares entitled to vote, exclusive of the shares beneficially owned by the acquiring person, and consummates the proposed control share acquisition within 180 days after shareholder approval. If such approval is not obtained, the statute provides that the shares acquired may not be voted for a period of one year from the date of acquisition, the shares will be nontransferable on HEI’s books for one year after acquisition and HEI, during the one-year period, shall have the right to call the shares for redemption either at the prices at which the shares were acquired or at book value per share as of the last day of the fiscal quarter ended prior to the date of the call for redemption.

Under provisions of the Hawaii Revised Business Corporation Act, subject to certain exceptions, HEI may not be a party to a merger or consolidation unless the merger or consolidation is approved by the holders of at least 75% of all of the issued and outstanding voting stock of HEI.

Under provisions of Hawaii law regulating public utilities, not more than 25% of the issued and outstanding voting stock of certain public utility corporations, including HECO and its wholly owned electric utility subsidiaries, may be held, directly or indirectly, by any single foreign corporation or any single nonresident alien, or held by any person, without the prior approval of the PUC. The acquisition of more than 25% of the issued and outstanding voting stock of HEI in one or more transactions might be deemed to result in the holding of more than 25% of the voting stock of HECO and its electric utility subsidiaries. In addition, HEI is subject to an agreement entered into with the PUC when HECO became a wholly owned subsidiary of HEI. This agreement provides that the acquisition of HEI by a third party, whether by purchase, merger, consolidation or otherwise, requires the prior written approval of the PUC.

Federal law restricts acquisitions of a bank and any entity considered to be its holding company by establishing thresholds of “control,” the acquisition of which requires prior regulatory approval, and by limiting the types of persons and entities eligible to acquire such control. The primary federal banking regulator of American Savings Bank, F.S.B. (“ASB”) is the Office of Thrift Supervision (“OTS”). As a result of HEI’s indirect ownership of ASB, both HEI and HEI Diversified, Inc. (“HEIDI”), the direct parent corporation of ASB, are also subject to a certain degree of regulation by the OTS as “unitary savings and loan holding companies” (i.e., companies whose subsidiaries include a savings association and one or more nonfinancial subsidiaries). The Gramm-Leach-Bliley Act prohibits the creation of new so-called “unitary savings and loan holding companies,” although the unitary savings and loan holding company relationship among HEI, HEIDI and ASB is “grandfathered” under this Act so that HEI and its subsidiaries will be able to continue to engage in their current activities. The effect of this prohibition is that any acquisition of HEI is likely to require a divestiture of ASB or of its assets and liabilities. Federal law also limits the persons and entities eligible to acquire ASB or its assets and liabilities.

The thresholds of “control” which will trigger the need for notice to the OTS and, in certain instances, prior OTS approval are, with respect to transactions for which OTS is the primary federal banking regulator, set forth in federal statutes and the OTS regulations. Generally, no company, or any director or officer of a savings and loan holding company, or person who owns, or controls or holds with power to vote more than 25% of the voting stock of such holding company, may acquire control of a bank insured by the FDIC or its holding company without the prior written approval of the OTS. In addition, no person (other than certain persons affiliated with a savings and loan holding company) may acquire control of a bank or savings and loan holding company, unless the OTS has been given 60 days’ prior written notice of the acquisition and has not objected to it. “Control” in this context means the acquisition of, control of, or holding proxies representing, more than 25% of the voting shares of HEI or the power to control in any manner the election of a majority of the directors of HEI. Moreover, under OTS regulations, one would be determined, subject to rebuttal, to have acquired control if one acquires more than 10% of the voting shares of HEI and is subject to one of certain specified “control factors.” Anyone acquiring more than 10%, or additional stock above 10%, of any class of shares of HEI is required to file a certification with the OTS. Companies that are already qualified as savings and loan association holding companies are subject to even lower thresholds of voting share acquisition than the more generally applicable 25% and 10% thresholds just described. Such companies may not acquire more than 5% of the voting shares of HEI without prior OTS approval.

Dividend Reinvestment and Stock Purchase Plan

Any individual of legal age or entity is eligible to participate in the HEI Dividend Reinvestment and Stock Purchase Plan by making an initial cash investment in Common Stock, subject to applicable laws and regulations and the requirements of the plan. Holders of HEI Common Stock, and holders of preferred stock of HEI’s electric utility subsidiaries (HECO, HELCO and MECO), may automatically reinvest some or all of their dividends to purchase additional shares of Common Stock at market prices (as defined in the plan). Participants in the plan may also purchase additional shares of Common Stock at market prices (as defined in the plan) by making cash contributions to the plan. HEI reserves the right to suspend, modify or terminate the plan at any time. Shares of Common Stock issued under the plan may either be newly issued shares or shares purchased by the plan on the open market. Participants do not pay brokerage commissions in connection with purchases of newly issued shares, but do pay their pro rata share of brokerage commissions if the plan purchases shares for participants on the open market.

Item 6. Exhibits


HEI Exhibit 3(ii).1		HEI’s Amended and Restated Bylaws

HEI Exhibit 12.1		Hawaiian Electric Industries, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, nine months ended September 30, 2007 and 2006 and years ended December 31, 2006, 2005, 2004, 2003 and 2002

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

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

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

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

HEI Exhibit 99.1		News release, dated November 1, 2007, “Hawaiian Electric Industries, Inc. Reports Third Quarter 2007 Earnings”

HEI Exhibit 99.2		Agreement of resignation, appointment and acceptance, dated as of October 19, 2007, by and among HEI, U.S. Bank National Association and CITIBANK, N.A.

HECO Exhibit 3(ii).2		HECO’s Amended and Restated Bylaws

HECO Exhibit 12.2		Hawaiian Electric Company, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, nine months ended September 30, 2007 and 2006 and years ended December 31, 2006, 2005, 2004, 2003 and 2002

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

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

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

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

SIGNATURES

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


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

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

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

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

Date: November 2, 2007		Date: November 2, 2007