HAWAIIAN ELECTRIC CO INC - Quarter Report: 2008 September (Form 10-Q)

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

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, 2008

¨	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, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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 31, 2008
Hawaiian Electric Industries, Inc. (Without Par Value)		85,129,645 Shares
Hawaiian Electric Company, Inc. ($6-2/3 Par Value)		12,805,843 Shares (not publicly traded)

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended September 30, 2008

INDEX


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

	PART I. FINANCIAL INFORMATION

	Item 1.	Financial Statements

		Hawaiian Electric Industries, Inc. and Subsidiaries
1		Consolidated Statements of Income (unaudited) - three and nine months ended September 30, 2008 and 2007
2		Consolidated Balance Sheets (unaudited) - September 30, 2008 and December 31, 2007
3		Consolidated Statements of Changes in Stockholders’ Equity (unaudited) - nine months ended September 30, 2008 and 2007
4		Consolidated Statements of Cash Flows (unaudited) - nine months ended September 30, 2008 and 2007
5		Notes to Consolidated Financial Statements (unaudited)

		Hawaiian Electric Company, Inc. and Subsidiaries
17		Consolidated Statements of Income (unaudited) - three and nine months ended September 30, 2008 and 2007
18		Consolidated Balance Sheets (unaudited) - September 30, 2008 and December 31, 2007
19		Consolidated Statements of Changes in Common Stock Equity (unaudited) - nine months ended September 30, 2008 and 2007
20		Consolidated Statements of Cash Flows (unaudited) - nine months ended September 30, 2008 and 2007
21		Notes to Consolidated Financial Statements (unaudited)
43	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
43		HEI Consolidated
51		Electric Utilities
75		Bank
80	Item 3.	Quantitative and Qualitative Disclosures About Market Risk
81	Item 4.	Controls and Procedures

	PART II. OTHER INFORMATION

82	Item 1.	Legal Proceedings
82	Item 1A.	Risk Factors
84	Item 2	Unregistered Sales of Equity Securities and Use of Proceeds
84	Item 5.	Other Information
85	Item 6.	Exhibits
87	Signatures

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended September 30, 2008

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.). Former subsidiaries include ASB Service Corporation (dissolved in January 2004), ASB Realty Corporation (dissolved in May 2005) and AdCommunications, Inc. (dissolved in May 2007).

CHP		Combined heat and power

Company		When used in Hawaiian Electric Industries, Inc. sections, the “Company” refers to Hawaiian Electric Industries, Inc. and its direct and indirect subsidiaries, including, without limitation, Hawaiian Electric Company, Inc. and its subsidiaries (listed under HECO); HEI Diversified, Inc. and its subsidiary, American Savings Bank, F.S.B. and its subsidiaries (listed under ASB); Pacific Energy Conservation Services, Inc.; HEI Properties, Inc.; HEI Investments, Inc.; Hawaiian Electric Industries Capital Trust II and Hawaiian Electric Industries Capital Trust III (inactive financing entities); and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.). Former subsidiaries of HEI (other than former subsidiaries of HECO and ASB and former subsidiaries of HEI sold or dissolved prior to 2004) include Hycap Management, Inc. (dissolution completed in 2007); Hawaiian Electric Industries Capital Trust I (dissolved and terminated in 2004), HEI Preferred Funding, LP (dissolved and terminated in 2004), Malama Pacific Corp. (discontinued operations, dissolved in June 2004), and HEI Power Corp. (discontinued operations, dissolved in 2006) and its dissolved subsidiaries. (*unconsolidated subsidiaries as of January 1, 2004). When used in Hawaiian Electric Company, Inc. sections, the “Company” refers to Hawaiian Electric Company, Inc. and its direct subsidiaries.

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

DBEDT		State of Hawaii Department of Business, Economic Development and Tourism

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

ECAC		Energy cost adjustment clauses

EITF		Emerging Issues Task Force

Energy Agreement		Agreement dated October 20, 2008 and signed by the Governor of the State of Hawaii, the State of Hawaii Department of Business, Economic Development and Tourism, the Division of Consumer Advocacy of the Department of Commerce and Consumer Affairs, and HECO, for itself and on behalf of its electric utility subsidiaries committing to actions to develop renewable energy and reduce dependence on fossil fuels in support of the HCEI

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
HCEI		Hawaii Clean Energy Initiative

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, Renewable Hawaii, Inc., Uluwehiokama Biofuels Corp. and HECO Capital Trust III. Former subsidiaries include HECO Capital Trust I (dissolved and terminated in 2004)* and HECO Capital Trust II (dissolved and terminated in 2004). (unconsolidated subsidiaries as of January 1, 2004).

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., Hawaiian Electric Industries Capital Trust II, Hawaiian Electric Industries Capital Trust III and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.). Former subsidiaries (other than those sold or dissolved prior to 2004) are listed under Company.

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 wholly owned subsidiary of Hawaiian Electric Industries, Inc.

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

Kalaeloa		Kalaeloa Partners, L.P.

kV		Kilovolt

kw		Kilowatts

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 option

OPEB		Postretirement benefits other than pensions

OTS		Office of Thrift Supervision, Department of Treasury

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

RPS		Renewable portfolio standards

SAR		Stock appreciation right

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

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 and/or the actual performance of collateral underlying loans and mortgage-related securities held by American Savings Bank, F.S.B. (ASB)), decisions concerning the extent of the presence of the federal government and military in Hawaii, and the implications and potential impacts of the current capital market conditions and the Emergency Economic Stabilization Act of 2008 (President Bush administration’s plan for a $700 billion bailout of the financial industry);

•

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 ability of the Company to access credit markets to obtain commercial paper and other short-term and long-term debt financing and to access capital markets to issue preferred stock or hybrid securities (the utilities) and common stock (HEI) under volatile and challenging market conditions;

•

the risks inherent in changes in the value of and market for securities available for sale and in the value of 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 ASB’s cost of funds);

•

the effects of the implementation of the Energy Agreement with the State of Hawaii and Consumer Advocate setting forth the goals and objectives of a Hawaii Clean Energy Initiative (HCEI) and of the fulfillment by the utilities of their commitments under the Energy Agreement;

•

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 risks associated with increasing reliance on renewable energy, as contemplated under the Energy Agreement, including the availability of non-fossil fuel supplies for renewable generation and the operational impacts of adding intermittent sources of renewable energy to the electric grid;

•

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, regulatory changes resulting from the HCEI, 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 Office of Thrift Supervision (OTS) and other governmental authorities (such as consent orders, 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 international accounting standards or new accounting principles, continued regulatory accounting under Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” and the possible effects of applying Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46R, “Consolidation of Variable Interest Entities,” and Emerging Issues Task Force (EITF) 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 assets 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 risks of suffering losses and incurring liabilities that are uninsured or having insurance coverages with a troubled or failing insurer (e.g., American International Group Inc.); and

•

other risks or uncertainties described elsewhere in this report and in other 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
	2008			2007			2008			2007
Revenues
Electric utility	$	827,788		$	567,615		$	2,139,798		$	1,508,005
Bank		87,675			105,507			279,469			317,493
Other		(32	)		339			(164	)		2,749

		915,431			673,461			2,419,103			1,828,247

Expenses
Electric utility		775,941			536,249			1,981,572			1,434,858
Bank		62,983			86,960			262,406			260,824
Other		2,378			2,235			8,648			10,698

		841,302			625,444			2,252,626			1,706,380

Operating income (loss)
Electric utility		51,847			31,366			158,226			73,147
Bank		24,692			18,547			17,063			56,669
Other		(2,410	)		(1,896	)		(8,812	)		(7,949	)

		74,129			48,017			166,477			121,867

Interest expense—other than on deposit liabilities and other bank borrowings		(19,345	)		(19,589	)		(56,780	)		(59,382	)
Allowance for borrowed funds used during construction		967			656			2,564			1,840
Preferred stock dividends of subsidiaries		(471	)		(474	)		(1,417	)		(1,420	)
Allowance for equity funds used during construction		2,426			1,336			6,432			3,770

Income from before income taxes		57,706			29,946			117,276			66,675
Income taxes		20,425			10,065			40,892			22,481

Net income	$	37,281		$	19,881		$	76,384		$	44,194

Basic earnings per common share	$	0.44		$	0.24		$	0.91		$	0.54

Diluted earnings per common share	$	0.44		$	0.24		$	0.91		$	0.54

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

Weighted-average number of common shares outstanding		84,625			82,481			84,052			81,949
Dilutive effect of stock-based compensation		217			159			130			231

Adjusted weighted-average shares		84,842			82,640			84,182			82,180

Ratio of earnings to fixed charges (SEC method)
Excluding interest on ASB deposits								2.11			1.53

Including interest on ASB deposits								1.76			1.35

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

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)


(dollars in thousands)	September 30, 2008			December 31, 2007
Assets
Cash and equivalents	$	166,709		$	145,855
Federal funds sold		35,039			64,000
Accounts receivable and unbilled revenues, net		370,481			294,447
Available-for-sale investment and mortgage-related securities		766,045			2,140,772
Investment in stock of Federal Home Loan Bank of Seattle (estimated fair value $97,764)		97,764			97,764
Loans receivable, net		4,159,007			4,101,193
Property, plant and equipment, net of accumulated depreciation of $1,824,210 and $1,749,386		2,823,342			2,743,410
Regulatory assets		273,640			284,990
Other		465,820			338,405
Goodwill, net		83,080			83,080

	$	9,240,927		$	10,293,916

Liabilities and stockholders’ equity
Liabilities
Accounts payable	$	256,759		$	202,299
Deposit liabilities		4,182,648			4,347,260
Short-term borrowings—other than bank		230,566			91,780
Other bank borrowings		683,452			1,810,669
Long-term debt, net—other than bank		1,210,901			1,242,099
Deferred income taxes		176,255			155,337
Regulatory liabilities		282,308			261,606
Contributions in aid of construction		304,977			299,737
Other		558,168			573,409

		7,886,034			8,984,196

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: 85,080,748 shares and 83,431,513 shares		1,111,034			1,072,101
Retained earnings		223,294			225,168
Accumulated other comprehensive loss, net of tax benefits		(13,728	)		(21,842	)

		1,320,600			1,275,427

	$	9,240,927		$	10,293,916

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

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Changes in Stockholders’ Equity (unaudited)


(in thousands, except per share amounts)	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, 2007	83,432	$	1,072,101	$	225,168		$	(21,842	)	$	1,275,427
Comprehensive income:
Net income	—		—		76,384			—			76,384
Net unrealized losses on securities:
Net unrealized losses on securities arising during the period, net of tax benefits of $1,842	—		—		—			(2,788	)		(2,788	)
Less: reclassification adjustment for net realized losses included in net income, net of tax benefits of $6,915	—		—		—			10,472			10,472
Retirement benefit plans:
Amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes of $2,775	—		—		—			4,358			4,358
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $2,501	—		—		—			(3,928	)		(3,928	)

Comprehensive income	—		—		76,384			8,114			84,498

Issuance of common stock, net	1,649		38,933		—			—			38,933
Common stock dividends ($0.93 per share)	—		—		(78,258	)		—			(78,258	)

Balance, September 30, 2008	85,081	$	1,111,034	$	223,294		$	(13,728	)	$	1,320,600

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
Retirement benefit 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 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

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
(in thousands)	2008			2007
Cash flows from operating activities
Net income	$	76,384		$	44,194
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment		113,423			111,007
Other amortization		3,927			9,275
Provision for loan losses		4,034			3,900
Writedown of utility plant		—			11,701
Deferred income taxes		12,186			(18,068	)
Allowance for equity funds used during construction		(6,432	)		(3,770	)
Excess tax benefits from share-based payment arrangements		(572	)		(346	)
Loans receivable originated and purchased, held for sale		(159,327	)		(31,699	)
Proceeds from sale of loans receivable, held for sale		157,293			31,904
Net loss on sale of investment and mortgage-related securities		17,388			—
Changes in assets and liabilities
Increase in accounts receivable and unbilled revenues, net		(76,034	)		(28,147	)
Increase in fuel oil stock		(79,693	)		(35,904	)
Increase in accounts payable		54,460			54,232
Change in prepaid and accrued income taxes and utility revenue taxes		(29,640	)		18,744
Changes in other assets and liabilities		(13,278	)		2,955

Net cash provided by operating activities		74,119			169,978

Cash flows from investing activities
Available-for-sale investment and mortgage-related securities purchased		(411,658	)		(224,096	)
Principal repayments on available-for-sale investment and mortgage-related securities		489,740			443,493
Proceeds from sale of available-for-sale investment and mortgage-related securities		1,291,609			—
Proceeds from sale of other investments		—			8,879
Net increase in loans held for investment		(55,828	)		(240,078	)
Capital expenditures		(172,948	)		(139,122	)
Contributions in aid of construction		12,266			13,112
Other		724			5,721

Net cash provided by (used in) investing activities		1,153,905			(132,091	)

Cash flows from financing activities
Net decrease in deposit liabilities		(164,612	)		(188,342	)
Net increase (decrease) in short-term borrowings with original maturities of three months or less		138,786			(75,175	)
Net increase (decrease) in retail repurchase agreements		(23,290	)		50,814
Proceeds from other bank borrowings		1,719,085			904,532
Repayments of other bank borrowings		(2,820,119	)		(791,335	)
Proceeds from issuance of long-term debt		18,707			230,421
Repayment of long-term debt		(50,000	)		(136,000	)
Excess tax benefits from share-based payment arrangements		572			346
Net proceeds from issuance of common stock		21,067			15,449
Common stock dividends		(62,493	)		(60,938	)
Decrease in cash overdraft		(8,582	)		(12,076	)
Other		(5,252	)		(6,855	)

Net cash used in financing activities		(1,236,131	)		(69,159	)

Net decrease in cash and equivalents and federal funds sold		(8,107	)		(31,272	)
Cash and equivalents and federal funds sold, beginning of period		209,855			257,301

Cash and equivalents and federal funds sold, end of period	$	201,748		$	226,029

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, 2007 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, 2008 and June 30, 2008.

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, 2008 and December 31, 2007 and the results of its operations for the three and nine months ended September 30, 2008 and 2007 and its cash flows for the nine months ended September 30, 2008 and 2007. 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, 2008
Revenues from external customers	$	827,731	$	87,675	$	25		$	915,431
Intersegment revenues (eliminations)		57		—		(57	)		—

Revenues		827,788		87,675		(32	)		915,431

Profit (loss)*		40,879		24,607		(7,780	)		57,706
Income taxes (benefit)		14,947		9,202		(3,724	)		20,425

Net income (loss)		25,932		15,405		(4,056	)		37,281

Nine months ended September 30, 2008
Revenues from external customers		2,139,667		279,469		(33	)		2,419,103
Intersegment revenues (eliminations)		131		—		(131	)		—

Revenues		2,139,798		279,469		(164	)		2,419,103

Profit (loss)*		125,014		16,934		(24,672	)		117,276
Income taxes (benefit)		47,065		5,046		(11,219	)		40,892

Net income (loss)		77,949		11,888		(13,453	)		76,384

Assets (at September 30, 2008)		3,692,204		5,514,788		33,935			9,240,927

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

*	Income (loss) before income taxes.

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

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

(3) Electric utility subsidiary

For HECO’s consolidated financial information, including its commitments and contingencies, see pages 17 through 42.

(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)	2008		2007		2008			2007
Interest and dividend income
Interest and fees on loans	$	61,100	$	61,817	$	186,312		$	182,191
Interest and dividends on investment and mortgage-related securities		9,898		26,497		57,078			85,090

		70,998		88,314		243,390			267,281

Interest expense
Interest on deposit liabilities		14,070		20,381		47,909			61,951
Interest on other borrowings		4,616		20,243		40,030			57,230

		18,686		40,624		87,939			119,181

Net interest income		52,312		47,690		155,451			148,100
Provision for loan losses		1,979		2,700		4,034			3,900

Net interest income after provision for loan losses		50,333		44,990		151,417			144,200

Noninterest income
Fees from other financial services		6,318		7,153		18,554			20,539
Fee income on deposit liabilities		7,328		6,583		20,889			19,095
Fee income on other financial products		1,771		1,977		5,214			5,845
Loss on sale of securities		—		—		(17,388	)		—
Other income		1,260		1,480		8,810			4,733

		16,677		17,193		36,079			50,212

Noninterest expense
Compensation and employee benefits		19,172		16,173		56,451			52,733
Occupancy		5,489		5,418		16,276			15,707
Equipment		3,175		3,630		9,510			10,893
Services		3,688		6,385		13,531			22,638
Data processing		2,794		2,596		8,019			7,799
Loss on early extinguishment of debt		—		—		39,843			—
Other expense		8,085		9,456		26,932			27,972

		42,403		43,658		170,562			137,742

Income before income taxes		24,607		18,525		16,934			56,670
Income taxes		9,202		6,794		5,046			20,761

Net income	$	15,405	$	11,731	$	11,888		$	35,909

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

Consolidated Balance Sheets Data (unaudited)


(in thousands)	September 30, 2008			December 31, 2007
Assets
Cash and equivalents	$	128,351		$	140,023
Federal funds sold		35,039			64,000
Available-for-sale investment and mortgage-related securities		766,045			2,140,772
Investment in stock of Federal Home Loan Bank of Seattle		97,764			97,764
Loans receivable, net		4,159,007			4,101,193
Other		245,502			234,661
Goodwill, net		83,080			83,080

	$	5,514,788		$	6,861,493

Liabilities and stockholder’s equity
Deposit liabilities-noninterest-bearing	$	721,496		$	652,055
Deposit liabilities-interest-bearing		3,461,152			3,695,205
Other borrowings		683,452			1,810,669
Other		118,144			108,800

		4,984,244			6,266,729

Common stock		327,874			325,467
Retained earnings		213,165			287,710
Accumulated other comprehensive loss, net of tax benefits		(10,495	)		(18,413	)

		530,544			594,764

	$	5,514,788		$	6,861,493

Other borrowings consisted of securities sold under agreements to repurchase and advances from the Federal Home Loan Bank (FHLB) of Seattle of $269 million and $414 million, respectively, as of September 30, 2008 and $765 million and $1.0 billion, respectively, as of December 31, 2007. The $1.1 billion decrease in other borrowings from December 31, 2007 to September 30, 2008 was primarily due to the early extinguishment of certain borrowings from the balance sheet restructure described below.

As of September 30, 2008, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.3 billion.

Balance sheet restructure. In June 2008, ASB undertook and substantially completed the restructuring of its balance sheet through the sale of mortgage-related securities and agency notes and the early extinguishment of certain borrowings to strengthen future profitability ratios and enhance future net interest margin, while remaining “well-capitalized” and without significantly impacting future net income and interest rate risk. On June 25, 2008, ASB completed a series of transactions which resulted in the sales to various broker/dealers of available-for-sale agency and private issue mortgage-related securities and agency notes with a weighted average yield of 4.33% for approximately $1.3 billion. ASB used the proceeds from the sales of these mortgage-related securities and agency notes to retire debt with a weighted average cost of 4.70%, comprised of approximately $0.9 billion of FHLB advances and $0.3 billion of securities sold under agreements to repurchase. These transactions resulted in a charge to net income of $36 million in the second quarter of 2008 ($12 million after-tax attributable to realized losses on the sales of the mortgage-related securities and agency notes and $24 million after-tax attributable to fees associated with the early retirement of the FHLB advances and securities sold under agreements to repurchase). Although the sales of the mortgage-related securities and agency notes resulted in realized losses in the second quarter of 2008, a portion of the losses on these available-for-sale securities had been previously recognized as unrealized losses in ASB’s equity as a result of mark-to-market charges to other comprehensive income in earlier periods.

ASB subsequently purchased approximately $0.3 billion of short-term agency notes and entered into approximately $0.2 billion of FHLB advances to facilitate the timing of the release of certain collateral. These notes and advances had original maturities up to December 31, 2008.

As a result of the balance sheet restructuring, ASB freed-up capital and planned to dividend up to approximately $75 million over the next several quarters, subject to OTS approval. In the third quarter of 2008, ASB received OTS approval to pay and paid a dividend to HEI (through ASB’s direct parent, HEI Diversified, Inc.) of $54.7 million. ASB represented to the OTS that the dividend would be paid only to the extent that its payment would not cause its Tier I leverage ratio to fall below 8%. HEI used the dividend to repay commercial paper and for other corporate purposes.

Guarantees. In October 2007, ASB, as a member financial institution of Visa U.S.A. Inc., received restricted shares of Visa, Inc. (Visa) as a result of a restructuring of Visa U.S.A. Inc. in preparation for an initial public offering by Visa. As a part of the restructuring, ASB entered into judgment and loss sharing agreements with Visa in order to apportion financial responsibilities arising from any potential adverse judgment or negotiated settlements related to indemnified litigation involving Visa. In November 2007, Visa announced that it had reached a settlement with American Express regarding certain of this litigation. In the fourth quarter of 2007, ASB recorded a charge of $0.3 million for its proportionate share of this settlement and a charge of approximately $0.6 million for potential losses arising from indemnified litigation that has not yet settled, which estimated fair value is highly judgmental. In March 2008, Visa funded an escrow account designed to address potential liabilities arising from litigation covered in the Retrospective Responsibility Plan and, based on the amount funded in the escrow account, ASB recorded a receivable of $0.4 million for its proportionate share of the escrow account. In October 2008, Visa reached a settlement in principle in a case brought by Discover Financial Services. The final settlement will be contingent upon Visa member approval. This case is “covered litigation” under Visa’s Retrospective Responsibility Plan and ASB’s proportionate share of this settlement is estimated to be $0.3 million. Because the extent of ASB’s obligations under this agreement depends entirely upon the occurrence of future events, ASB’s maximum potential future liability under this agreement is not determinable.

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 in prior years. ASB has and continues to take steps to remediate these deficiencies and to strengthen ASB’s overall compliance programs. ASB agreed to a consent order (Order) issued by the OTS on January 23, 2008 as a result of issues relating to ASB’s compliance with certain laws and regulations, including the Bank Secrecy Act and Anti-Money Laundering (BSA/AML). The Order does not impose restrictions on ASB’s business activities; however it requires, among other things, various actions by ASB to strengthen its BSA/AML Program and its Compliance Management Program. ASB has implemented several initiatives to enhance its BSA/AML Program that address the requirements of the Order, and is on course with its remediation efforts. ASB is also implementing initiatives to enhance its Compliance Management Program in accordance with the requirements of the Order.

ASB also consented to the concurrent issuance of an order by the OTS for the assessment of a Civil Money Penalty of $37,730 related to non-compliance with certain flood insurance laws and regulations and paid the penalty in January 2008.

ASB is unable to predict what other actions, if any, may be initiated by the OTS and other governmental authorities against ASB as a result of these deficiencies, or the impact of any such measures or actions on ASB or the Company.

SFAS No. 157, Fair Value Measurements. SFAS No. 157 (which defines fair value, establishes a framework for measuring fair value under GAAP and expands disclosures about fair value measurements) was adopted prospectively and only partially applied as of January 1, 2008. In accordance with FASB Staff Position (FSP) No. FAS 157-2, the Company has delayed the application of SFAS No. 157 to ASB’s goodwill until January 1, 2009. FSP No. 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” was issued in October 2008, and did not have an impact on fair value measurements for ASB or the Company.

Fair value is the price that would be received to sell an asset in an orderly transaction between market participants at the measurement date. ASB grouped its financial assets measured at fair value in three levels outlined in SFAS No.157 as follows:


Level 1:		Inputs to the valuation methodology are quoted prices, unadjusted, for identical assets or liabilities in active markets. A quoted price in an active market provides the most reliable evidence of fair value and shall be used to measure fair value whenever available.

Level 2:		Inputs to the valuation methodology include quoted prices for similar assets or liabilities in active markets; inputs to the valuation methodology include quoted prices for identical or similar assets or liabilities in markets that are not active; or inputs to the valuation methodology that are derived principally from or can be corroborated by observable market data by correlation or other means.

Level 3:		Inputs to the valuation methodology are unobservable and significant to the fair value measurement. Level 3 assets and liabilities include financial instruments whose value is determined using discounted cash flow methodologies, as well as instruments for which the determination of fair value requires significant management judgment or estimation.

Assets Measured at Fair Value on a Recurring Basis

Available-for-sale investment and mortgage-related securities. While securities held in ASB’s investment portfolio trade in active markets, they do not trade on listed exchanges nor do the specific holdings trade in quoted markets by dealers or brokers. All holdings are valued using market-based approaches that are taken from identical or similar market transactions. Inputs to these valuation techniques reflect the assumptions market participants would use in pricing the asset based on market data obtained from independent sources.

The table below presents the balances of assets measured at fair value on a recurring basis:


			Fair value measurements using
Description	September 30, 2008		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
	(in millions)
Available-for-sale securities	$	766	$	—	$	766	$	—

Assets Measured at Fair Value on a Nonrecurring Basis

Loans. ASB does not record loans at fair value on a recurring basis. However, from time to time, ASB records nonrecurring fair value adjustments to loans to reflect specific reserves on loans based on the current appraised value of the collateral or unobservable market assumptions. These adjustments to fair value usually result from the application of lower-of-cost-or-market accounting or write-downs of individual loans. Unobservable assumptions reflect ASB’s own estimate of the fair value of collateral used in valuing the loan.

The table below presents the balances of assets measured at fair value on a nonrecurring basis:


			Fair value measurements using
Description	September 30, 2008		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
	(in millions)
Loans	$	3.9	$	—	$	—	$	3.9

Specific reserves as of September 30, 2008 were $4.3 million and were included in loans receivable held for investment, net. For the nine months ended September 30, 2008, there were no adjustments to fair value for ASB’s loans held for sale.

FDIC Restoration Plan. Under the Federal Deposit Insurance Reform Act of 2005 (the Reform Act), the FDIC may set the designated reserve ratio within a range of 1.15% to 1.50%. The Reform Act requires that the FDIC’s Board of Directors adopt a restoration plan when the Deposit Insurance Fund (DIF) reserve ratio falls below 1.15% or is expected to within six months. Recent failures have significantly increased the DIF’s loss provisions, resulting in a decline in the reserve ratio. As of June 30, 2008, the reserve ratio had fallen 18 basis points since the previous quarter to 1.01%. To restore the reserve ratio to 1.15%, higher assessment rates are required. The FDIC is proposing changes to the assessment system to ensure that riskier institutions will bear a greater share of the proposed increase in assessments. Under the proposed rules, financial institutions in Risk Category I, the lowest risk group, will have an initial base assessment rate within the range of 10 to 14 basis points. After applying adjustments for unsecured debt, secured liabilities and brokered deposits, the total base assessment rate for financial institutions in Risk Category I would be within the range of 8 to 21 basis points. The FDIC recommends the proposed rates become effective April 1, 2009. The FDIC also recommends raising the current rates uniformly by seven basis points for the assessment for the quarter beginning January 1, 2009. ASB is classified in Risk Category I and anticipates its assessment rate to be 12.5 basis points for the quarter beginning January 1, 2009 decreasing to 10 to 11 basis points for the quarter beginning April 1, 2009. Currently, ASB’s assessment is 5.5 basis points of deposits, or $0.6 million for the quarter ended September 30, 2008.

Deposit Insurance Coverage. The Emergency Economic Stabilization Act of 2008 was signed into law on October 3, 2008 and temporarily raises the basic limit on federal deposit insurance coverage from $100,000 to $250,000 per depositor, effective October 3, 2008 through December 31, 2009. The legislation provides that the basic deposit insurance coverage limit will return to $100,000 after December 31, 2009 for all interest bearing deposit categories except for Individual Retirement Accounts and Certain Retirement Accounts, which will continue to be insured at $250,000 per owner. Under the FDIC’s Temporary Liquidity Guarantee Program, non-interest bearing deposit transaction accounts will be provided unlimited deposit insurance coverage until December 31, 2009.

Capital Purchase Program. On October 14, 2008, President Bush’s Working Group on Financial Markets announced a voluntary Capital Purchase Program (CPP) to encourage U.S. financial institutions to build capital to increase the flow of financing to U.S. businesses and consumers and to support the U.S. economy.

Under the CPP, the U.S. Treasury (Treasury) will purchase non-voting senior preferred securities from qualifying U.S.-controlled banks and thrifts and bank and thrift holding companies. The senior preferred securities will pay cumulative dividends at a rate of 5% per annum for the first five years and a rate of 9% thereafter. In conjunction with the purchase of the senior preferred securities, the Treasury will receive 10-year warrants to purchase common stock of the qualifying institution with an aggregate market price equal to 15% of the amount of the senior preferred investment, with an exercise price equal to the market price of the issuer’s common stock at the time of issuance, calculated on a 20 trading day trailing average. Financial institutions participating in the program must also adopt the Treasury’s standards for executive compensation and corporate governance, for the period during which the Treasury holds equity issued under the program. Financial institutions must submit their application to participate in the program by November 14, 2008. ASB has elected not to participate in the program.

(5) Retirement benefits

Defined benefit plans. For the first nine months of 2008, HECO contributed $9.3 million and HEI contributed $0.6 million to their respective retirement benefit plans, compared to $8.2 million and $0.1 million, respectively, in the first nine months of 2007. The Company’s current estimate of contributions to its retirement benefit plans in 2008 is $14.5 million (including $13.7 million to be made by the utilities and $0.8 million by HEI), compared to contributions of $13.1 million in 2007 (including $12.1 million made by the utilities, $0.9 million by ASB and $0.1 million by HEI). In addition, the Company expects to pay directly $1.3 million of benefits in 2008, comparable to the $1.3 million paid in 2007.

For the first nine months of 2008, the Company’s defined benefit retirement plans’ assets generated realized and unrealized losses, including investment management fees, of 15.9%. The market value of the defined benefit retirement plans’ assets as of September 30, 2008 was $0.9 billion compared to $1.1 billion at December 31, 2007, a decline of approximately $196 million, or 18.6%. During the first nine months of 2008, the trusts distributed $42 million in benefits to, or on behalf of, plan participants and beneficiaries. Because of the significant decline in the value of plan assets through September 30, 2008, and assuming no further improvement or decline, the Company expects that the 2009 minimum required contribution to the qualified pension plans, calculated in accordance with the Pension Protection Act (first effective January 1, 2008), will be an estimated $21 million after reduction for a credit balance compared to no contribution anticipated at the beginning of 2008.

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)	2008⁽¹⁾			2007			2008			2007			2008⁽¹⁾			2007			2008			2007
Service cost	$	7,255		$	7,746		$	1,215		$	1,166		$	21,100		$	23,250		$	3,562		$	3,606
Interest cost		14,987			14,494			2,690			2,598			44,778			43,358			8,318			8,232
Expected return on plan assets		(18,335	)		(17,091	)		(2,745	)		(2,619	)		(54,836	)		(51,291	)		(8,227	)		(7,321	)
Amortization of unrecognized transition obligation		—			—			785			785			2			2			2,354			2,354
Amortization of prior service cost (gain)		(116	)		(50	)		3			3			(305	)		(148	)		10			10
Recognized actuarial loss		1,692			2,796			—			—			5,073			8,486			—			—

Net periodic benefit cost		5,483			7,895			1,948			1,933			15,812			23,657			6,017			6,881
Impact of PUC D&Os		1,327			—			308			—			4,531			—			731			—

Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	6,810		$	7,895		$	2,256		$	1,933		$	20,343		$	23,657		$	6,748		$	6,881

⁽¹⁾	Due to the freezing of ASB’s defined benefit plan as of December 31, 2007 (see below), there are no amounts for ASB employees for certain components (service cost, amortizations and recognized actuarial loss).

The Company recorded retirement benefits expense of $20 million and $25 million in the first nine months of 2008 and 2007, respectively, and charged the remaining amounts primarily to electric utility plant.

Also, see Note 4, “Retirement benefits,” of HECO’s Notes to Consolidated Financial Statements.

Effective December 31, 2007, ASB ended the accrual of benefits in, and the addition of new participants to, ASB’s defined benefit pension plan. The change to the plan did not affect the vested pension benefits of former participants, including ASB retirees, as of December 31, 2007. All active participants who were employed by ASB on December 31, 2007 became fully vested in their accrued pension benefit as of December 31, 2007.

Defined contribution plan. On January 1, 2008, ASB began providing for employer contributions for ASB employees to HEI’s retirement savings plan with two contribution components in addition to employee contributions: 1) 401(k) matching of 100% on the first 4% of eligible pay contributed by participants; and 2) a discretionary employer value-sharing contribution (based on the participant’s number of years of vested service) up to 6% of eligible pay that is not contingent on contributions by participants. For the first nine months of 2008, ASB’s total expense for its employees participating in the HEI retirement savings plan was $3.3 million and contributions were $1.3 million. ASB’s current estimate of contributions to the retirement savings plan in 2008 is $1.9 million.

(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 (4.5 million shares available for issuance under outstanding and future grants and awards as of September 30, 2008) 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:


	Three months ended September 30		Nine months ended September 30
($ in millions)	2008	2007	2008	2007
Share-based compensation expense¹	0.3	0.4	0.5	1.1
Income tax benefit	0.1	0.1	0.1	0.3

¹	The Company has not capitalized any share-based compensation cost. For the third quarter of 2008, the estimated forfeiture rate for SARs was 14.3% and the estimated forfeiture rate for restricted stock was 30.3%.

Nonqualified stock options. Information about HEI’s NQSOs is summarized as follows:


September 30, 2008		Outstanding & Exercisable
Year of grant	Range of exercise prices	Number of options	Weighted- average remaining contractual life	Weighted- average exercise price
1999	$17.61	1,000	0.6	$17.61
2000	14.74	46,000	1.6	14.74
2001	17.96	67,000	2.6	17.96
2002	21.68	122,000	3.5	21.68
2003	20.49	141,500	4.1	20.49

	$14.74 – 21.68	377,500	3.3	$19.72

As of December 31, 2007, NQSOs outstanding totaled 603,800, with a weighted-average exercise price of $19.68. As of September 30, 2008, exercisable NQSO had an aggregate intrinsic value (including dividend equivalents) of $5.3 million.

NQSO activity and statistics are summarized as follows:


	Three months ended September 30				Nine months ended September 30
($ in thousands, except prices)	2008			2007	2008		2007
Shares granted		—		—		—		—
Shares forfeited		—		—		—		—
Shares expired		8,000		—		8,000		—
Shares vested		—		—		—		79,000
Aggregate fair value of vested shares		—		—		—	$	350
Shares exercised		6,000		—		218,300		56,200
Weighted-average exercise price	$	20.49		—	$	19.64	$	19.70
Cash received from exercise	$	123		—	$	4,287	$	1,107
Intrinsic value of shares exercised¹	$	31		—	$	2,217	$	575
Tax benefit (expense) realized for the deduction of exercises	$	(67	)	—	$	784	$	224
Dividend equivalent shares distributed under Section 409A		—		—		6,125		21,892
Weighted-average Section 409A distribution price		—		—	$	22.38	$	26.15
Intrinsic value of shares distributed under Section 409A		—		—	$	137	$	572
Tax benefit realized for Section 409A distributions		—		—	$	53	$	223

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, 2008, all NQSOs were vested.

Stock appreciation rights. Information about HEI’s SARs is summarized as follows:


September 30, 2008		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	295,000	3.1	$26.02	295,000	3.1	$26.02
2005	26.18	502,000	4.2	26.18	218,000	1.1	26.18

	$26.02 – 26.18	797,000	3.8	$26.12	513,000	2.2	$26.09

As of December 31, 2007, the shares underlying SARs outstanding totaled 857,000, with a weighted-average exercise price of $26.12. As of September 30, 2008, the SARs outstanding and exercisable (including dividend equivalents) had an aggregate intrinsic value of $3.4 million and $2.0 million, respectively.

SARs activity and statistics are summarized as follows:


	Three months ended September 30			Nine months ended September 30
($ in thousands, except prices)	2008		2007	2008		2007
Shares granted		—	—		—		—
Shares forfeited		—	18,000		30,000		18,000
Shares expired		—	—		—		—
Shares vested		18,000	—		79,000		51,000
Aggregate fair value of vested shares	$	107	—	$	436	$	269
Shares exercised		30,000	—		30,000		4,000
Weighted-average exercise price	$	26.02	—	$	26.02	$	26.18
Cash received from exercise		—	—		—		—
Intrinsic value of shares exercised¹	$	117	—	$	117	$	3
Tax benefit realized for the deduction of exercises	$	45	—	$	45	$	1
Dividend equivalent shares distributed under Section 409A		—	—		—		23,760
Weighted-average Section 409A distribution price		—	—		—	$	26.15
Intrinsic value of shares distributed under Section 409A		—	—		—	$	621
Tax benefit realized for Section 409A distributions		—	—		—	$	242

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, 2008, there was $0.1 million of total unrecognized compensation cost related to SARs and that cost is expected to be recognized over a weighted average period of 0.6 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, 2008 and 2007 a total of 6,125 and 45,652 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 September 30, 2008 and December 31, 2007, restricted stock shares outstanding totaled 161,200 and 146,000, respectively, with a weighted-average grant date fair value of $25.51 and $25.82, respectively. The grant date fair value of a grant of a restricted stock share was the closing or average price of HEI common stock on the date of grant.

Information about HEI’s awards of restricted stock is summarized as follows:


	Three months ended September 30				Nine months ended September 30
($ in thousands)	2008		2007		2008		2007
Shares vested		6,170		—		6,170		16,000
Shares forfeited		4,830		1,000		23,330		1,000
Grant date fair value	$	124	$	26	$	605	$	26
Shares granted		2,000		9,300		44,700		75,700
Grant date fair value	$	49	$	193	$	1,104	$	1,931

The tax benefits realized for the tax deductions related to restricted stock were $0.1 million and $0.2 million for the first nine months of 2008 and 2007, respectively.

As of September 30, 2008, there was $2.1 million of total unrecognized compensation cost related to nonvested restricted stock. The cost is expected to be recognized over a weighted-average period of 2.8 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, 2008 and 2007, the Company paid interest (net of amounts capitalized and including bank interest) to non-affiliates amounting to $137 million and $167 million, respectively.

For the nine months ended September 30, 2008 and 2007, the Company paid income taxes amounting to $93 million and $5 million, respectively. The significant increase in taxes paid in the first nine months of 2008 versus 2007 was due primarily to the increase in operating income and the change in the Treasury regulations governing the calculation of estimated taxes due in 2008. The new regulations generally require a more ratable payment of estimated taxes. In calculating 2007 estimated taxes, taxable income was significantly larger in the fourth quarter when compared to the first three quarters, resulting in a larger portion of the 2007 taxes paid with the extension filed in the first quarter of 2008.

Supplemental disclosures of noncash activities. Noncash increases in common stock for director and officer compensatory plans of the Company were $1.5 million and $2.0 million for the nine months ended September 30, 2008 and 2007, 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 $16 million and $15 million for the nine month periods ended September 30, 2008 and 2007, 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 by acquiring for cash its common shares through open market purchases rather than the issuance of additional shares. Since March 6, 2007, HEI has been satisfying those requirements by the issuance of additional shares.

(9) Recent accounting pronouncements and interpretations

Business combinations. In December 2007, the FASB issued SFAS No. 141R, “Business Combinations.” SFAS No. 141R requires an acquiring entity to recognize all the assets acquired and liabilities assumed at the acquisition-date fair value with limited exceptions. Under SFAS No. 141R, acquisition costs will generally be expensed as incurred, noncontrolling interests will be valued at acquisition-date fair value, and acquired contingent liabilities will be recorded at acquisition-date fair value and subsequently measured at the higher of such amount or the amount determined under existing guidance for non-acquired contingencies. The Company must adopt SFAS No. 141R for all business combinations for which the acquisition date is on or after January 1, 2009. Because the impact of adopting SFAS No. 141R will be dependent on future acquisitions, if any, management cannot predict such impact.

Noncontrolling interests. In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements.” SFAS No. 160 requires the recognition of a noncontrolling interest (i.e., a minority interest) as equity in the consolidated financial statements, separate from the parent’s equity, and requires the amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on the face of the income statement. Under SFAS No. 160, changes in the parent’s ownership interest that leave control intact are accounted for as capital transactions (i.e., as increases or decreases in ownership), a gain or loss will be recognized when a subsidiary is deconsolidated based on the fair value of the noncontrolling equity investment (not carrying amount), and entities must provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and of the noncontrolling owners. The Company must adopt SFAS No. 160 on January 1, 2009 prospectively, except for the presentation and disclosure requirements which must be applied retrospectively. Thus, beginning January 1, 2009, “Preferred stock of subsidiaries—not subject to mandatory redemption” will be presented as a separate component of “Stockholders’ equity” rather than as “Minority interests” in the mezzanine section between liabilities and equity on the balance sheet, dividends on preferred stock of subsidiaries will be deducted from net income to arrive at net income for common stock on the income statement, and a column for “Preferred stock of subsidiaries—not subject to mandatory redemption” will be added to the statement of changes in stockholders’ equity.

Participating Securities. In June 2008, the FASB issued FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities,” according to which unvested share-based-payment awards that contain non-forfeitable rights to dividends or dividend equivalents are “participating securities” as defined in EITF 03-6 and therefore should be included in computing earnings per share using the two-class method. The Company must adopt FSP EITF 03-6-1 in the first quarter of 2009 retrospectively. Based on the restricted stock shares granted historically, management believes the impact of adoption of FSP EITF 03-6-1 on the Company’s financial statements will not be material.

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)	2008			2007			2008			2007
Operating revenues	$	826,124		$	561,720		$	2,135,265		$	1,499,766

Operating expenses
Fuel oil		377,157			222,721			900,455			549,771
Purchased power		202,125			144,918			530,146			390,161
Other operation		61,599			54,113			176,600			154,949
Maintenance		25,174			28,594			72,777			85,799
Depreciation		35,419			34,273			106,254			102,812
Taxes, other than income taxes		74,201			51,389			194,058			138,839
Income taxes		15,035			4,976			47,507			15,974

		790,710			540,984			2,027,797			1,438,305

Operating income		35,414			20,736			107,468			61,461

Other income
Allowance for equity funds used during construction		2,426			1,336			6,432			3,770
Other, net		1,486			3,819			3,693			(1,330	)

		3,912			5,155			10,125			2,440

Income before interest and other charges		39,326			25,891			117,593			63,901

Interest and other charges
Interest on long-term debt		11,879			11,478			35,413			34,364
Amortization of net bond premium and expense		632			621			1,902			1,813
Other interest charges		1,352			1,075			3,397			4,090
Allowance for borrowed funds used during construction		(967	)		(656	)		(2,564	)		(1,840	)
Preferred stock dividends of subsidiaries		228			228			686			686

		13,124			12,746			38,834			39,113

Income before preferred stock dividends of HECO		26,202			13,145			78,759			24,788
Preferred stock dividends of HECO		270			270			810			810

Net income for common stock	$	25,932		$	12,875		$	77,949		$	23,978

Ratio of earnings to fixed charges (SEC method)								3.83			1.84

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, 2008			December 31, 2007
Assets
Utility plant, at cost
Land	$	37,790		$	38,161
Plant and equipment		4,223,353			4,131,226
Less accumulated depreciation		(1,715,765	)		(1,647,113	)
Plant acquisition adjustment, net		6			41
Construction in progress		214,587			151,179

Net utility plant		2,759,971			2,673,494

Current assets
Cash and equivalents		14,769			4,678
Customer accounts receivable, net		207,877			146,112
Accrued unbilled revenues, net		137,668			114,274
Other accounts receivable, net		4,701			6,915
Fuel oil stock, at average cost		171,564			91,871
Materials and supplies, at average cost		37,693			34,258
Prepayments and other		21,138			9,490

Total current assets		595,410			407,598

Other long-term assets
Regulatory assets		273,640			284,990
Unamortized debt expense		14,796			15,635
Other		48,387			42,171

Total other long-term assets		336,823			342,796

	$	3,692,204		$	3,423,888

Capitalization and liabilities
Capitalization
Common stock, $6 2/3 par value, authorized 50,000 shares; outstanding 12,806 shares	$	85,387		$	85,387
Premium on capital stock		299,214			299,214
Retained earnings		788,565			724,704
Accumulated other comprehensive income, net of income taxes		1,328			1,157

Common stock equity		1,174,494			1,110,462
Cumulative preferred stock — not subject to mandatory redemption		34,293			34,293
Long-term debt, net		903,901			885,099

Total capitalization		2,112,688			2,029,854

Current liabilities
Short-term borrowings—nonaffiliates		140,995			28,791
Accounts payable		184,219			137,895
Interest and preferred dividends payable		18,644			14,719
Taxes accrued		189,414			189,637
Other		39,313			57,799

Total current liabilities		572,585			428,841

Deferred credits and other liabilities
Deferred income taxes		168,810			162,113
Regulatory liabilities		282,308			261,606
Unamortized tax credits		59,102			58,419
Other		191,734			183,318

Total deferred credits and other liabilities		701,954			665,456

Contributions in aid of construction		304,977			299,737

	$	3,692,204		$	3,423,888

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Changes in Common Stock Equity (unaudited)


(in thousands, except per share amounts)	Common stock			Premium on capital stock		Retained earnings			Accumulated other comprehensive income (loss)			Total
(in thousands, except per share amounts)	Shares	Amount		Premium on capital stock		Retained earnings			Accumulated other comprehensive income (loss)			Total
Balance, December 31, 2007	12,806	$	85,387	$	299,214	$	724,704		$	1,157		$	1,110,462
Comprehensive income:
Net income	—		—		—		77,949			—			77,949
Retirement benefit plans:
Amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes of $2,611	—		—		—		—			4,099			4,099
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory asset, net of taxes of $2,502	—		—		—		—			(3,928	)		(3,928	)

Comprehensive income	—		—		—		77,949			171			78,120

Common stock dividends	—		—		—		(14,088	)		—			(14,088	)

Balance, September 30, 2008	12,806	$	85,387	$	299,214	$	788,565		$	1,328		$	1,174,494

Balance, December 31, 2006	12,806	$	85,387	$	299,214	$	700,252		$	(126,650	)	$	958,203
Comprehensive income:
Net income	—		—		—		23,978			—			23,978
Retirement benefit plans - amortization of net loss, prior service gain 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 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

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	2008			2007
	(in thousands)
Cash flows from operating activities
Income before preferred stock dividends of HECO	$	78,759		$	24,788
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities
Depreciation of property, plant and equipment		106,254			102,812
Other amortization		6,426			6,450
Writedown of utility plant		—			11,701
Deferred income taxes		6,588			(17,925	)
Tax credits, net		1,503			1,944
Allowance for equity funds used during construction		(6,432	)		(3,770	)
Changes in assets and liabilities
Increase in accounts receivable		(59,551	)		(22,073	)
Increase in accrued unbilled revenues		(23,394	)		(7,996	)
Increase in fuel oil stock		(79,693	)		(35,904	)
Increase in materials and supplies		(3,435	)		(4,420	)
Increase in regulatory assets		(28	)		(2,129	)
Increase in accounts payable		46,324			44,547
Change in prepaid and accrued income and utility revenue taxes		(7,969	)		12,039
Changes in other assets and liabilities		(5,386	)		17,515

Net cash provided by operating activities		59,966			127,579

Cash flows from investing activities
Capital expenditures		(170,321	)		(135,090	)
Contributions in aid of construction		12,266			13,112
Other		749			5,259

Net cash used in investing activities		(157,306	)		(116,719	)

Cash flows from financing activities
Common stock dividends		(14,088	)		(13,507	)
Preferred stock dividends		(810	)		(810	)
Proceeds from issuance of long-term debt		18,707			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		112,204			(83,482	)
Decrease in cash overdraft		(8,582	)		(12,076	)

Net cash provided by (used in) financing activities		107,431			(5,454	)

Net increase in cash and equivalents		10,091			5,406
Cash and equivalents, beginning of period		4,678			3,859

Cash and equivalents, end of period	$	14,769		$	9,265

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, 2007 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, 2008 and June 30, 2008.

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, 2008 and December 31, 2007 and the results of their operations for the three and nine months ended September 30, 2008 and 2007 and their cash flows for the nine months ended September 30, 2008 and 2007. 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, 2008 and December 31, 2007 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, 2008 and 2007 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, 2008, 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 (i.e., 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 utilities) 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, 2008 totaled $530 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $106 million, $214 million, $69 million and $46 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, since 2004 HECO has continued its efforts to obtain from the IPPs the information necessary to make the determinations required under FIN 46R. In January 2005, 2006, 2007 and 2008, HECO and its subsidiaries 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 declined to provide necessary information, except that Kalaeloa provided the information pursuant to the amendments to the PPA (see below) and an entity owning a wind farm provided information as required under the PPA. Management has concluded that the consolidation of two entities owning wind farms was not required as MECO and HELCO do not have variable interests in the entities because the PPAs do not require them to absorb any variability of the entities.

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 also has a steam delivery contract with another customer, the term of which coincides with the PPA. The cogeneration 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.

(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, 2008 and 2007, HECO and its subsidiaries included approximately $187 million and $134 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

(4) Retirement benefits

Defined benefit plans. For the first nine months of 2008, HECO and its subsidiaries contributed $9.3 million to their retirement benefit plans, compared to $8.2 million in the first nine months of 2007. HECO and its subsidiaries’ current estimate of contributions to their retirement benefit plans in 2008 is $13.7 million, compared to contributions of $12.1 million in 2007. In addition, HECO and its subsidiaries expect to pay directly $0.5 million of benefits in 2008, compared to $0.1 million paid in 2007.

For the first nine months of 2008, HECO and its subsidiaries’ defined benefit retirement plans’ assets generated realized and unrealized losses, including investment management fees, of 15.9%. The market value of the defined benefit retirement plan’s assets as of September 30, 2008 was $0.8 billion compared to $1.0 billion at December 31, 2007, a decline of approximately $179 million, or 18.7%. During the first nine months of 2008, the trusts distributed $40 million in benefits to, or on behalf of, plan participants and beneficiaries. Because of the significant decline in the value of plan assets through September 30, 2008, and assuming no further improvement or decline, HECO and its subsidiaries expect that the 2009 minimum required contribution to the qualified pension plans, calculated in accordance with the Pension Protection Act (first effective January 1, 2008), will be an estimated $21 million after reduction for a credit balance compared to no contribution anticipated at the beginning of 2008.

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)	2008			2007			2008			2007			2008			2007			2008			2007
Service cost	$	6,863		$	6,418		$	1,179		$	1,137		$	20,039		$	19,109		$	3,464		$	3,516
Interest cost		13,528			12,951			2,617			2,515			40,446			38,637			8,081			7,998
Expected return on plan assets		(16,333	)		(15,311	)		(2,698	)		(2,580	)		(48,861	)		(45,789	)		(8,090	)		(7,201	)
Amortization of unrecognized transition obligation		—			—			783			783			—			1			2,348			2,348
Amortization of prior service gain		(191	)		(191	)		—			—			(572	)		(572	)		—			—
Recognized actuarial loss		1,646			2,625			—			—			4,935			7,861			—			—

Net periodic benefit cost		5,513			6,492			1,881			1,855			15,987			19,247			5,803			6,661
Impact of PUC D&Os		1,327			—			308			—			4,531			—			731			—

Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	6,840		$	6,492		$	2,189		$	1,855		$	20,518		$	19,247		$	6,534		$	6,661

HECO and its subsidiaries recorded retirement benefits expense of $20 million in each of the first nine months of 2008 and 2007. The electric utilities charged a portion of the net periodic benefit costs to plant.

In HELCO’s 2006, HECO’s 2007 and MECO’s 2007 test year rate cases, the utilities and the Consumer Advocate proposed adoption of pension and postretirement benefits other than pensions (OPEB) tracking mechanisms, which are intended to smooth the impact to ratepayers of potential fluctuations in pension and OPEB costs. Under the tracking mechanisms, costs determined under SFAS Nos. 87 and 106, as amended, that are over/under amounts allowed in rates are charged/credited to a regulatory asset/liability. The regulatory asset/liability for each utility will be amortized over 5 years beginning with the respective utility’s next rate case.

The pension tracking mechanisms generally require the electric utilities to fund only the minimum level required under the law until the existing pension assets are reduced to zero, at which time the electric utilities 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 OPEB tracking mechanisms generally require the electric utilities to make contributions to the OPEB trust in the amount of the actuarially calculated net periodic benefit costs.

A pension funding study 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 its 2007 interim decisions for HELCO’s 2006, HECO’s 2007 and MECO’s 2007 test year rate cases, the PUC approved the adoption of the proposed pension and OPEB tracking mechanisms on an interim basis (subject to the PUC’s final decision and orders (D&Os)) and established the amount of net periodic benefit costs to be recovered in rates by each utility. HECO reflected the continuation of the pension and OPEB tracking mechanisms in its rate increase application based on a 2009 test year.

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 and was allowed to be included in HELCO’s rate base, net of deferred income taxes. In the interim PUC decisions in HECO’s and MECO’s 2007 test year rate cases, their pension assets ($51 million and $1 million, respectively, as of December 31, 2007) were not included in their rate bases and amortization of the pension assets was not included as part of the pension tracking mechanisms adopted in the proceedings on an interim basis. The issue of whether to amortize HECO’s prepaid pension asset, if allowed to be included in rate base by the PUC, has been deferred until HECO’s next rate case proceeding. HECO’s pension asset was not included in rate base, and amortization of the pension asset was not included in revenue requirements, in HECO’s rate increase application based on a 2009 test year.

(5) Commitments and contingencies

Hawaii Clean Energy Initiative (HCEI). In January 2008, the State of Hawaii and U.S. Department of Energy (DOE) signed a memorandum of understanding establishing the HCEI. The stated purpose of the HCEI is to establish a long-term partnership between the State of Hawaii and DOE that will result in a fundamental and sustained transformation in the way in which renewable energy efficiency resources are planned and used in the State. HECO has been working with the State and the DOE and other stakeholders to align the utility’s energy plans with the State’s plans.

The parties recognize that the move toward a more renewable and distributed and intermittent powered system will pose increased operating challenges to the utilities and that there is a need to assure that Hawaii preserves a stable electric grid to minimize disruption to service quality and reliability. They further recognize that Hawaii needs a system of utility regulation to transform the utilities from traditional sales-based companies to energy services companies while preserving financially sound utilities.

Many of the actions and programs included in the agreement will require approval of the PUC in proceedings that will need to be initiated by the PUC or the utilities.

Among the major provisions of the agreement most directly affecting HECO and its subsidiaries are the following:

The agreement provides for the parties to pursue an overall goal of providing 70% of Hawaii’s electricity and ground transportation energy needs from clean energy sources, including renewable energy and energy efficiency, by 2030. The ground transportation energy needs included in this goal include a contemplated move in Hawaii to electrification of transportation and the use of electric utility capacity in off peak hours to recharge vehicles and batteries. To promote the transportation goals, the agreement provides for the parties to evaluate and implement incentives to encourage adoption of electric vehicles, and to lead by example by acquiring hybrid or electric-only vehicles for government and utility fleets.

To help achieve the HCEI goals, the agreement further provides for the parties to seek amendment to the Hawaii Renewable Portfolio Standards (RPS) law (law which establishes renewable energy requirements for electric utilities that sell electricity for consumption in the State) to increase the current requirements from 20% to 25% by the year 2020, and to add a further RPS goal of 40% by the year 2030. The revised RPS law would also require that after 2014 the RPS goal be met solely with renewable energy generation versus including energy savings from energy efficiency measures. However, energy savings from energy efficiency measures would be counted toward the achievement of the overall HCEI 70% goal.

To further encourage the contributions of energy efficiency to the overall HCEI goal, the agreement provides for the parties to seek establishment of energy efficiency goals through an Energy Efficiency Portfolio Standard.

To help fund energy efficiency programs, incentives, program administration, customer education, and other related program costs, as expended by the third-party administrator for the energy efficiency programs or by program contractors, which may include the utilities, the agreement provides that the parties will request that the PUC establish a Public Benefits Fund (PBF) that is funded by collecting 1% of HECO, HELCO and MECO revenues in years one and two after implementation of a PBF; 1.5% in years three and four; and 2% thereafter. Such PBF funds are expected to be collected from customers in lieu of the amounts currently collected for specific existing demand-side management programs.

The agreement provides for the establishment of a Clean Energy Infrastructure Surcharge (CEIS). The CEIS, which will need to be approved by the PUC, is to be designed to expedite cost recovery for a variety of

infrastructure that supports greater use of renewable energy or grid efficiency within the utility systems (such as advanced metering, energy storage, interconnections and interfaces). The agreement provides that the surcharge should be available to recover costs that would normally be expensed in the year incurred and capital costs (including the allowed return on investment, AFUDC, depreciation, applicable taxes and other approved costs), and could also be used to recover costs stranded by clean energy initiatives.

HECO and its subsidiaries will continue to negotiate with developers of currently proposed projects (identified in the agreement) to integrate approximately 1,100 MW from a variety of renewable energy sources, including solar, biomass, wind, ocean thermal energy conversion, wave, and others. This includes HECO’s commitment to integrate, with the assistance of the State of Hawaii, up to 400 MW of wind power into the Oahu electrical grid that would be imported via a yet-to-be-built undersea transmission cable system from wind farms proposed by developers to be built on the islands of Lanai and/or Molokai. Utilizing technical resources such as the U.S. Department of Energy national laboratories, HECO, along with the other parties, have committed to work together to evaluate, assess and address the operational challenges for integrating such a large increment of wind into its grid system on Oahu. The State and HECO agree to work together to ensure the supporting infrastructure needed for the Oahu grid is in place to reliably accommodate this large increment of wind power, including appropriate additional storage capacity investments and any required utility system connections or interfaces with the cable and the wind farm facilities.

With respect to the undersea transmission cable system, the State agrees to seek, with HECO and/or developers’ reasonable assistance, federal grant or loan assistance to pay for the undersea cable system. In the event federal funding is unavailable, the State will employ its best effort to fund the undersea cable system through a prudent combination of taxpayer and ratepayer sources. There is no obligation on the part of HECO to fund any of the cost of the undersea cable. However, in the event HECO funds any part of the cost to develop the undersea cable system and assumes any ownership of the cable system, all reasonably incurred capital costs and expenses are intended to be recoverable through the CEIS.

As another method of accelerating the acquisition of renewable energy by the utilities, the agreement includes support of the parties for the development of a feed-in tariff system with standardized purchase prices for renewable energy. The PUC is requested to conclude an investigative proceeding by March 2009 to determine the best design for feed-in tariffs that support the HCEI goals, considering such factors as categories of renewables, size or locational limits for projects qualifying for the feed-in tariff, what annual limits should apply to the amount of renewables allowed to utilize the feed-in tariff, what factors to incorporate into the prices set for feed-in tariff payments, and other terms and conditions. Based on these understandings, the agreement provides that the parties request the PUC to suspend the pending intra-governmental wheeling and avoided cost (Schedule Q) dockets for a period of 12 months. On October 24, 2008, the PUC opened an investigative proceeding to examine the implementation of feed-in tariffs. The utilities and Consumer Advocate were named as initial parties to the proceeding and must file a joint proposal on feed-in tariffs that addresses all of the related factors identified in the Energy Agreement with the PUC by December 23, 2008. The parties are also required to submit a procedural schedule designed to allow the PUC to complete its deliberations and issue a decision by March 31, 2009.

The agreement also provides that system-wide caps on net energy metering should be removed. Instead, all distributed generation interconnections, including net metered systems, should be limited on a per-circuit basis to no more than 15% of peak circuit demand, to encourage the development of more cost effective distributed resources while still maintaining safe reliable service.

The agreement includes support of the parties for the development and use of renewable biofuels for electricity generation, including the testing of the technical feasibility of using biofuel or biofuel blends in HECO, HELCO and MECO generating units. The parties agree that use of biofuels in the utilities’ generating units, particularly biofuels from local sources, can contribute to achieving RPS requirements and decreasing greenhouse gas emissions, while avoiding major capital investment for new, replacement generation.

In recognition of the need to recover the infrastructure and other investments required to support significantly increased levels of renewable energy and to eliminate the potential conflict between encouraging energy efficiency and conservation and lower sales revenues, the parties agree that it is appropriate to adopt a regulatory rate-making model, which is subject to PUC approval, under which HECO, HELCO and MECO revenues would be

decoupled from KWH sales. If approved by the PUC, the new regulatory model, which is similar to the regulatory models currently used in California, would employ a revenue adjustment mechanism to track on an ongoing basis the differences between the amount of revenues allowed in the last rate case and (a) the current costs of providing electric service and (b) a reasonable return on and return of additional capital investment in the electric system. On October 24, 2008, the PUC opened an investigative proceeding to examine implementing a decoupling mechanism that would modify the traditional rate-making model by separating revenues and profits from KWH sales. The utilities and Consumer Advocate were named as initial parties to the proceeding and must file a joint proposal on decoupling that addresses all of the related factors identified in the Energy Agreement with the PUC by December 23, 2008. The parties are also required to submit a procedural schedule designed to allow the PUC to complete its deliberations and issue a decision by the time of an interim decision in HECO’s 2009 test year rate case (approximately the summer of 2009).

The utilities would also continue to use existing PUC-approved tracking mechanisms for pension and other post-retirement benefits. The utilities would also be allowed an automatic revenue adjustment mechanism to reflect changes in state or federal tax rates. The PUC will be requested to incorporate implementation of the new regulatory model in the PUC’s future interim decision and order in HECO’s 2009 test year rate case. The agreement also contemplates that additional rate cases based on a 2009 test year will be filed by HELCO and MECO in order to provide their respective baselines for implementation of the new regulatory model.

The agreement confirms that the existing Energy Cost Adjustment Clause will continue, subject to periodic review by the PUC. As part of that review, the parties agree that the PUC will examine whether there are renewable energy projects from which the utility should have, but did not purchase energy or whether alternate fuel purchase strategies were appropriately used or not used.

With PUC approval, a separate surcharge would be established to allow HECO and its subsidiaries to pass through all reasonably incurred purchased power costs, including all capacity, operation and maintenance expenses and other non-energy payments approved by the PUC which are currently recovered through base rates, with the surcharge to be adjusted monthly and reconciled quarterly.

The agreement includes a number of other undertakings intended to accomplish the purposes and goals of the HCEI, subject to PUC approval and including, but not limited to: (a) promoting through specifically proposed steps greater use of solar energy through solar water heating, commercial and residential photovoltaic energy installations and concentrated solar power generation; (b) providing for the retirement or placement on reserve standby status of older and less efficient fossil fuel fired generating units as new, renewable generation is installed; (c) improvement and expansion of “load management” and “demand response” programs that allow the utilities to control customer loads to improve grid reliability and cost management; (d) the filing of PUC applications this year for approval of the installation of Advanced Metering Infrastructure, coupled with time-of-use or dynamic rate options for customers; (e) supporting prudent and cost effective investments in smart grid technologies, which become even more important as wind and solar generation is added to the grid; (f) including 10% of the energy purchased under feed-in tariffs in each utility’s respective rate base through January 2015; and (g) delinking prices paid under all new renewable energy contracts from oil prices.

Interim increases. 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 $25 million, which was implemented on April 5, 2007.

On October 22, 2007, the PUC issued, and HECO immediately implemented, an interim D&O in HECO’s 2007 test year rate case, granting HECO an increase of $70 million in annual revenues over rates effective at the time of the interim decision ($78 million in annual revenues over rates granted in the final decision in HECO’s 2005 test year rate case).

On December 21, 2007, the PUC issued, and MECO immediately implemented, an interim D&O in MECO’s 2007 test year rate case, granting MECO an increase of $13 million in annual revenues, or a 3.7% increase.

As of September 30, 2008, HECO and its subsidiaries had recognized $119 million of revenues with respect to interim orders ($6 million related to interim orders regarding certain integrated resource planning costs and $113 million related to interim orders with respect to interim surcharges to recover general rate increase requests).

Energy cost adjustment clauses (ECACs). Act 162 was signed into law in June 2006 and requires that any automatic fuel rate adjustment clause requested by a public utility in an application filed with the PUC be designed, as determined in the PUC’s discretion, to (1) fairly share the risk of fuel cost changes between the utility and its customers, (2) provide the utility with incentive to manage or lower its fuel costs and encourage greater use of renewable energy, (3) allow the utility to mitigate the risk of sudden or frequent fuel cost changes that cannot otherwise reasonably be mitigated through commercially reasonable means, such as through fuel hedging contracts, (4) preserve the utility’s financial integrity, and (5) minimize the utility’s need to apply for frequent general rate increases for fuel cost changes. While the PUC already had reviewed the automatic fuel adjustment clauses in rate cases, Act 162 requires that these five specific factors be addressed in the record.

In May 2008, the PUC issued a final D&O in HECO’s 2005 test year rate case in which the PUC agreed with the parties’ stipulation in the proceeding that it would not require the parties in the proceeding to submit a stipulated procedural schedule to address the Act 162 factors in the 2005 test year rate case proceeding, and stated it expects HECO and HELCO to develop information relating to the Act 162 factors for examination during their next rate case proceedings.

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. In April and December 2007, the PUC issued interim D&Os in the HELCO 2006 and MECO 2007 test year rate cases that reflected for purposes of the interim order the continuation of their ECACs, consistent with agreements reached between the Consumer Advocate and HELCO and MECO, respectively. The Consumer Advocate and MECO agreed that no further changes are required to MECO’s ECAC in order to comply with the requirements of Act 162.

In September 2007, HECO, the Consumer Advocate and the federal Department of Defense (DOD) agreed that the ECAC should continue in its present form for purposes of an interim rate increase in the HECO 2007 test year rate case 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 October 2007, the PUC issued an interim D&O, which reflected the continuation of HECO’s ECAC for purposes of the interim increase.

Management cannot predict the ultimate effect of the required Act 162 analysis on the continuation of the utilities’ existing ECACs, but the Energy Agreement confirms the intent of the parties that the existing ECACs will continue, subject to periodic review by the PUC. As part of that periodic review, the parties agree that the PUC will examine whether there are renewable energy projects from which the utility should have, but did not purchase energy or whether alternate fuel purchase strategies were appropriately used or not used.

Major projects. Many public utility projects require PUC approval and various permits from other governmental agencies. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits can result in significantly increased project costs or even cancellation of projects. Further, completion of projects is subject to various risks, such as problems or disputes with vendors. In the event a project does not proceed, or if the PUC disallows cost recovery for all or part of the project, project costs may need to be written off in amounts that could result in significant reductions in HECO’s consolidated net income. Significant projects (with capitalized and deferred costs accumulated through September 30, 2008 noted in parentheses) include HELCO’s ST-7 ($37 million) and HECO’s East Oahu Transmission Project ($36 million), Customer Information system ($20 million) and generating unit in and transmission line to Campbell Industrial Park ($58 million).

Campbell Industrial Park (CIP) generating unit. HECO is building a new 110 MW simple cycle combustion turbine (CT) generating unit at CIP and plans 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 mid-2009, fueled by biodiesel. 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 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 and the DOH issued the final air permit, which became effective at the end of June 2007. 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. HECO’s 2009 test year rate case application, filed in July 2008, requests inclusion of the Project investment in rate base when the new unit is placed in service (expected to be at the end of July 2009). Construction on the Project began in May 2008.

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).

As of September 30, 2008, HECO’s cost estimate for the Project (exclusive of the costs of the community benefit measures described above) was $164 million (of which $58 million had been incurred, including $3 million of AFUDC) and outstanding commitments for materials, equipment and outside services totaled $56 million. Management believes no adjustment to project costs is required as of September 30, 2008. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HECO may be required to write off a material portion or all of the project costs incurred in its efforts to put the project into service whether or not it is completed.

In August 2007, HECO entered into a contract with Imperium Services, LLC, to supply biodiesel for the planned generating unit, subject to PUC approval. Imperium Services, LLC agreed to comply with HECO’s procurement policy requiring sustainable sources of biofuel and biofuel feedstocks. In October 2007, HECO filed an application with the PUC for approval of this biodiesel supply contract. An evidentiary hearing on the application was held in October 2008, and the parties’ briefs will be filed later in 2008, after which the application will be ready for PUC decision-making.

East Oahu Transmission Project (EOTP). HECO had planned a project (EOTP) to construct a part underground 138 kilovolt (kV) line in order to close the gap between the Southern and Northern transmission corridors on Oahu and provide a third transmission line to a major substation. However, in 2002, an application for a permit, which would have allowed construction in a route through conservation district lands, was denied.

HECO continued to believe that the proposed reliability project was needed and, in 2003, filed an application with the PUC requesting approval to commit funds (currently estimated at $74 million; see costs incurred below) for an EOTP, revised to use a 46 kV system and modified route, none of which is in conservation district lands. The environmental review process for the EOTP, as revised, was completed in 2005.

In written testimony filed in 2005, a 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 of the permit in 2002, and the related allowance for funds used during construction (AFUDC) of $5 million at the time. 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 addresses. In October 2007, the PUC issued a final D&O approving HECO’s request to expend funds for the EOTP, but stating that the issue of recovery of the EOTP costs would be determined in a subsequent rate case, after the project is installed and in service.

Subject to obtaining other construction permits, HECO plans to construct the EOTP in two phases. The first phase is currently in construction and projected to be completed in 2010. The projected completion date of the second phase is being evaluated.

As of September 30, 2008, the accumulated costs recorded for the EOTP amounted to $36 million, including (i) $12 million of planning and permitting costs incurred prior to 2003, (ii) $7 million of planning, permitting and construction costs incurred after 2002 and (iii) $17 million for AFUDC. Management believes no adjustment to project costs is required as of September 30, 2008. However, if it becomes probable that the PUC will disallow

some or all of the incurred costs for rate-making purposes, HECO may be required to write off a material portion or all of the project costs incurred in its efforts to put the project into service whether or not it is completed.

HCEI Projects. While much of the renewable energy infrastructure contemplated by the Energy Agreement will be developed by others (e.g., a 400 MW wind farm on Lanai or Molokai would be constructed by a third party developer and the underwater cable to bring the power generated by the wind farm to Oahu is currently planned to be constructed and owned by the State), the utilities may be making substantial investments in related infrastructure.

In the Energy Agreement, the State agrees to support, facilitate and help expedite renewable projects, including expediting permitting processes.

HELCO generating units. In 1991, HELCO began planning to meet increased demand for electricity forecast for 1994. HELCO 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 the units would be converted to a 56 MW (net) dual-train combined-cycle unit. There were a number of environmental and other permitting challenges to construction of the units, including several lawsuits, which resulted in significant delays. However, in 2003, all but one of the parties actively opposing the plant expansion project 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. The settlement agreement required HELCO to undertake a number of actions, which have been completed or are ongoing. As a result of the final resolution of various proceedings due primarily to the Settlement Agreement, there are no pending lawsuits involving the project.

CT-4 and CT-5 became operational in mid-2004 and additional noise mitigation work is ongoing to ensure compliance with the applicable night-time noise standard. Currently, HELCO can operate CT-4 and CT-5 as required to meet its system needs.

HELCO has completed engineering and design activities and construction work for ST-7 is progressing towards completion in mid-2009. As of September 30, 2008, HELCO’s cost estimate for ST-7 was $92 million (of which $37 million had been incurred) and outstanding commitments for materials, equipment and outside services totaled $42 million, a substantial portion of which are subject to cancellation charges.

CT-4 and CT-5 costs incurred and allowed. HELCO’s capitalized costs for CT-4 and CT-5 and related supporting infrastructure amounted to $110 million. 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 2006 rate case proceeding, subject to PUC approval. Under the settlement, HELCO agreed to write-off approximately $12 million of the costs relating to CT-4 and CT-5, resulting in an after-tax charge to net income in the first quarter of 2007 of $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 D&O reflected the agreement to write-off $12 million of the CT-4 and CT-5 costs. However, the interim D&O does not commit the PUC to accept any of the amounts in the interim increase in its final D&O.

If it becomes probable that the PUC will disallow for rate-making purposes additional CT-4 and CT-5 costs in its final D&O or disallow any ST-7 costs, HELCO will be required to record an additional write-off.

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 response to inquiries by the Hawaii Department of Health (DOH), HECO has been involved since 1995 in a work group with several other potentially responsible parties (PRPs), including oil companies, in investigating and responding to historical subsurface petroleum contamination in the Honolulu Harbor area. The U.S. Environmental Protection Agency (EPA) became involved in the investigation in June 2000. Some of the PRPs (the Participating Parties) entered into a joint defense agreement and ultimately entered an Enforceable Agreement with the DOH. The Participating Parties are funding the 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. Although the Honolulu Harbor investigation involves four units—Iwilei, Downtown, Kapalama and Sand Island, all the investigative and remedial work has focused on the Iwilei Unit to date.

Besides subsurface investigation, assessments and preliminary oil removal tasks that have been conducted by the Participating Parties, HECO and others investigated their ongoing operations in the Iwilei Unit in 2003 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.

For administrative management purposes, the Iwilei Unit has been subdivided into four subunits. The Participating Parties have developed analyses of various remedial alternatives for the four subunits. The DOH uses the analyses to make a final determination of which remedial alternatives the Participating Parties will be required to implement. The DOH has completed remedial determinations for two subunits to date. The Participating Parties anticipate that the DOH will complete the remaining remediation determinations during the remainder of 2008. The Participating Parties are required to develop remedial designs for the various elements of the remediation determinations and has initiated the remedial design work for the two subunits for which the DOH has made remedial determinations. The Participating Parties anticipate that all remedial design work for those subunits will be completed by the end of 2009 or early 2010 and will begin implementation of the remedial design elements as they are approved by the DOH. Although the DOH has not yet made final remediation determinations for two of the subunits, the Participating Parties anticipate final determinations by mid-2009 and that the remedial design work will be completed during the first quarter of 2010 for those subunits.

Through September 30, 2008, HECO has accrued a total of $3.3 million (including $0.4 million in the first quarter of 2008) for estimates of HECO’s share of costs for continuing investigative work, remedial activities and monitoring for the Iwilei unit. As of September 30, 2008, the remaining accrual (amounts expensed less amounts expended) for the Iwilei unit was $1.8 million. Because (1) the full scope of work remains 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 located in the Downtown unit of the Honolulu Harbor site), the cost estimate may be subject to significant change and additional material 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 were to adopt BART implementation plans and schedules in accordance with the amended regional haze rule by December 2007. After Hawaii adopts its plan, which it has not done to date, HECO, HELCO and MECO will evaluate the plan’s impacts, if any. 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.

Hazardous Air Pollutant (HAP) Control. In February 2008, the federal Circuit Court of Appeals for the District of Columbia vacated the EPA’s Delisting Rule, which had removed coal- and oil-fired electric generating units (EGUs) from the list of sources requiring control under Section 112 of the Clean Air Act. The EPA’s request for a

rehearing was denied. The EPA is thus required to develop Maximum Achievable Control Technology (MACT) standards for oil-fired EGU HAP emissions, including nickel compounds. Depending on the MACT standards developed (and the success of a potential challenge, after the MACT standards are issued, that the EPA inappropriately listed oil-fired EGUs initially), costs to comply with the standards could be significant. The Company is currently evaluating its options regarding potential MACT standards for applicable HECO steam units.

In October 2008, the EPA petitioned the U.S. Supreme Court to review the decision of the Circuit Court of Appeals for the District of Columbia, which vacated the EPA’s Delisting Rule. Management cannot predict if the Supreme Court will take the case or, if it does take the case, whether it would overrule the Circuit Court of Appeals.

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. In 2004, the EPA issued a rule, which established design, construction and capacity standards for existing cooling water intake structures, such as those at HECO’s Kahe, Waiau and Honolulu generating stations, and required demonstrated compliance by March 2008. The rule provided a number of compliance options, some of which were far less costly than others. HECO had retained a consultant that was developing a cost effective compliance strategy.

In January 2007, the U.S. Circuit Court of Appeals for the Second Circuit issued a decision that remanded for further consideration and proceedings significant portions of the rule and found other portions to be impermissible. In July 2007, the EPA formally suspended the rule and 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. HECO facilities are subject to permit renewal in mid-2009 and may be subject to new permit conditions to address cooling water intake requirements at that time. In April 2008, the U. S. Supreme Court agreed to review the Court of Appeal’s rejection of a cost-benefit test to determine compliance options. It is now expected that the Supreme Court will hear the case in December 2008, with a decision issued in the first half of 2009. If the Supreme Court affirms the Court of Appeal’s decision, the compliance options available to HECO are reduced. Due to the uncertainties regarding the Court of Appeal’s decision, 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, 2008, approximately 58% of the electric utilities’ employees were members of the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260, Unit 8, which is the only union representing employees of the Company. On March 1, 2008, members of the union ratified new collective bargaining and benefit agreements with HECO, HELCO and MECO. The new agreements cover a three-year term, from November 1, 2007 to October 31, 2010, and provide for non-compounded wage increases of 3.5% effective November 1, 2007, 4% effective January 1, 2009 and 4.5% effective January 1, 2010.

Limited insurance. HECO and its subsidiaries purchase insurance coverages to protect themselves against loss or damage to their properties against claims made by third-parties and employees. However, the protection provided by such insurance is limited in significant respects and, in some instances, there is no coverage. HECO, HELCO and MECO’s overhead and underground transmission and distribution systems (with the exception of substation buildings and contents) have a replacement value roughly estimated at $4 billion and are uninsured. Similarly, HECO, HELCO and MECO have no business interruption insurance. If a hurricane or other uninsured catastrophic natural disaster were to occur, and if the PUC were not to allow the utilities to recover from ratepayers restoration costs and revenues lost from business interruption, their results of operations and financial condition could be materially adversely impacted. Also, certain insurance has substantial “deductibles”, limits on the maximum amounts that may be recovered and exclusions or limitations of coverage for claims related to certain perils. If a series of losses occurred, such as from a series of lawsuits in the ordinary course of business, each of which were subject to the deductible amount, or if the maximum limit of the available insurance were substantially exceeded, HECO, HELCO and MECO could incur losses in amounts that would have a material adverse effect on its results of operations and financial condition.

(6) Cash flows

Supplemental disclosures of cash flow information. For the nine months ended September 30, 2008 and 2007, HECO and its subsidiaries paid interest amounting to $33 million.

For the nine months ended September 30, 2008 and 2007, HECO and its subsidiaries paid income taxes amounting to $87 million and $6 million, respectively. The significant increase in taxes paid in the first nine months of 2008 versus 2007 was due primarily to the increase in operating income and the change in the Treasury regulations governing the calculation of estimated taxes due in 2008. The new regulations generally require a more ratable payment of estimated taxes. In calculating 2007 estimated taxes, taxable income was significantly larger in the fourth quarter when compared to the first three quarters, resulting in a larger portion of the 2007 taxes paid with the extension filed in the first quarter of 2008.

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 $6.4 million and $3.8 million for the nine months ended September 30, 2008 and 2007, 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) Reconciliation of electric utility operating income per HEI and HECO consolidated statements of income


	Three months ended September 30						Nine months ended September 30
(in thousands)	2008			2007			2008			2007
Operating income from regulated and nonregulated activities before income taxes (per HEI consolidated statements of income)	$	51,847		$	31,366		$	158,226		$	73,147
Deduct:
Income taxes on regulated activities		(15,035	)		(4,976	)		(47,507	)		(15,974	)
Revenues from nonregulated activities		(1,664	)		(5,895	)		(4,533	)		(8,239	)
Add: Expenses from nonregulated activities		266			241			1,282			12,527

Operating income from regulated activities after income taxes (per HECO consolidated statements of income)	$	35,414		$	20,736		$	107,468		$	61,461

(9) 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 for 2007, 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, 2008


(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and eliminations		HECO consolidated
Operating revenues	$	575,033		122,190		128,901		—		—		—		$	826,124

Operating expenses
Fuel oil		271,889		30,148		75,120		—		—		—			377,157
Purchased power		140,757		49,645		11,723		—		—		—			202,125
Other operation		44,377		7,619		9,603		—		—		—			61,599
Maintenance		16,574		4,485		4,115		—		—		—			25,174
Depreciation		20,553		7,818		7,048		—		—		—			35,419
Taxes, other than income taxes		51,485		10,923		11,793		—		—		—			74,201
Income taxes		8,728		3,675		2,632		—		—		—			15,035

		554,363		114,313		122,034		—		—		—			790,710

Operating income		20,670		7,877		6,867		—		—		—			35,414

Other income
Allowance for equity funds used during construction		1,822		463		141		—		—		—			2,426
Equity in earnings of subsidiaries		10,754		—		—		—		—		(10,754	)		—
Other, net		1,508		386		81		(14	)	(25	)	(450	)		1,486

		14,084		849		222		(14	)	(25	)	(11,204	)		3,912

Income (loss) before interest and other charges		34,754		8,726		7,089		(14	)	(25	)	(11,204	)		39,326

Interest and other charges
Interest on long-term debt		7,649		1,965		2,265		—		—		—			11,879
Amortization of net bond premium and expense		403		108		121		—		—		—			632
Other interest charges		1,216		434		152		—		—		(450	)		1,352
Allowance for borrowed funds used during construction		(716	)	(194	)	(57	)	—		—		—			(967	)
Preferred stock dividends of subsidiaries		—		—		—		—		—		228			228

		8,552		2,313		2,481		—		—		(222	)		13,124

Income (loss) before preferred stock dividends of HECO		26,202		6,413		4,608		(14	)	(25	)	(10,982	)		26,202
Preferred stock dividends of HECO		270		133		95		—		—		(228	)		270

Net income (loss) for common stock	$	25,932		6,280		4,513		(14	)	(25	)	(10,754	)	$	25,932

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)

Nine months ended September 30, 2008


(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and eliminations		HECO consolidated
Operating revenues	$	1,458,621		332,811		343,833		—		—		—		$	2,135,265

Operating expenses
Fuel oil		632,415		79,194		188,846		—		—		—			900,455
Purchased power		367,450		131,590		31,106		—		—		—			530,146
Other operation		125,108		23,979		27,513		—		—		—			176,600
Maintenance		48,008		12,785		11,984		—		—		—			72,777
Depreciation		61,657		23,454		21,143		—		—		—			106,254
Taxes, other than income taxes		132,595		30,110		31,353		—		—		—			194,058
Income taxes		28,158		9,978		9,371		—		—		—			47,507

		1,395,391		311,090		321,316		—		—		—			2,027,797

Operating income		63,230		21,721		22,517		—		—		—			107,468

Other income
Allowance for equity funds used during construction		4,957		1,069		406		—		—		—			6,432
Equity in earnings of subsidiaries		31,519		—		—		—		—		(31,519	)		—
Other, net		4,079		983		191		(54	)	(347	)	(1,159	)		3,693

		40,555		2,052		597		(54	)	(347	)	(32,678	)		10,125

Income (loss) before interest and other charges		103,785		23,773		23,114		(54	)	(347	)	(32,678	)		117,593

Interest and other charges
Interest on long-term debt		22,761		5,875		6,777		—		—		—			35,413
Amortization of net bond premium and expense		1,203		332		367		—		—		—			1,902
Other interest charges		3,004		1,205		347		—		—		(1,159	)		3,397
Allowance for borrowed funds used during construction		(1,942	)	(456	)	(166	)	—		—		—			(2,564	)
Preferred stock dividends of subsidiaries		—		—		—		—		—		686			686

		25,026		6,956		7,325		—		—		(473	)		38,834

Income (loss) before preferred stock dividends of HECO		78,759		16,817		15,789		(54	)	(347	)	(32,205	)		78,759
Preferred stock dividends of HECO		810		400		286		—		—		(686	)		810

Net income (loss) for common stock	$	77,949		16,417		15,503		(54	)	(347	)	(31,519	)	$	77,949

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 Balance Sheet (unaudited)

September 30, 2008


(in thousands)	HECO			HELCO		MECO		RHI	UBC	Reclassifications and Eliminations		HECO Consolidated
Assets
Utility plant, at cost
Land	$	28,462		4,982		4,346		—	—	—		$	37,790
Plant and equipment		2,545,166		856,512		821,675		—	—	—			4,223,353
Less accumulated depreciation		(1,016,132	)	(345,726	)	(353,907	)	—	—	—			(1,715,765	)
Plant acquisition adjustment, net		—		—		6		—	—	—			6
Construction in progress		145,239		57,819		11,529		—	—	—			214,587

Net utility plant		1,702,735		573,587		483,649		—	—	—			2,759,971

Investment in wholly owned subsidiaries, at equity		431,598		—		—		—	—	(431,598	)		—

Current assets
Cash and equivalents		9,112		2,102		3,384		140	31	—			14,769
Advances to affiliates		76,150		—		—		—	—	(76,150	)		—
Customer accounts receivable, net		137,910		37,875		32,092		—	—	—			207,877
Accrued unbilled revenues, net		99,033		20,037		18,598		—	—	—			137,668
Other accounts receivable, net		7,445		5,305		4,502		—	—	(12,551	)		4,701
Fuel oil stock, at average cost		131,109		16,196		24,259		—	—	—			171,564
Materials & supplies, at average cost		18,539		5,041		14,113		—	—	—			37,693
Prepayments and other		12,737		4,080		4,321		—	—	—			21,138

Total current assets		492,035		90,636		101,269		140	31	(88,701	)		595,410

Other long-term assets
Regulatory assets		202,773		37,973		32,894		—	—	—			273,640
Unamortized debt expense		9,997		2,325		2,474		—	—	—			14,796
Other		33,527		8,164		6,583		—	113	—			48,387

Total other long-term assets		246,297		48,462		41,951		—	113	—			336,823

	$	2,872,665		712,685		626,869		140	144	(520,299	)	$	3,692,204

Capitalization and liabilities
Capitalization
Common stock equity	$	1,174,494		218,252		213,077		128	141	(431,598	)	$	1,174,494
Cumulative preferred stock–not subject to mandatory redemption		22,293		7,000		5,000		—	—	—			34,293
Long-term debt, net		582,107		147,462		174,332		—	—	—			903,901

Total capitalization		1,778,894		372,714		392,409		128	141	(431,598	)		2,112,688

Current liabilities
Short-term borrowings-nonaffiliates		140,995		—		—		—	—	—			140,995
Short-term borrowings-affiliate		—		60,150		16,000		—	—	(76,150	)		—
Accounts payable		134,734		35,360		14,125		—	—	—			184,219
Interest and preferred dividends payable		11,691		3,340		3,791		—	—	(178	)		18,644
Taxes accrued		122,413		33,618		33,383		—	—	—			189,414
Other		28,979		9,387		13,305		12	3	(12,373	)		39,313

Total current liabilities		438,812		141,855		80,604		12	3	(88,701	)		572,585

Deferred credits and other liabilities
Deferred income taxes		136,905		19,738		12,167		—	—	—			168,810
Regulatory liabilities		196,582		49,342		36,384		—	—	—			282,308
Unamortized tax credits		32,714		13,579		12,809		—	—	—			59,102
Other		111,035		50,711		29,988		—	—	—			191,734

Total deferred credits and other liabilities		477,236		133,370		91,348		—	—	—			701,954

Contributions in aid of construction		177,723		64,746		62,508		—	—	—			304,977

	$	2,872,665		712,685		626,869		140	144	(520,299	)	$	3,692,204

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

December 31, 2007


(in thousands)	HECO			HELCO		MECO		RHI	UBC	Reclassifications and Eliminations		HECO Consolidated
Assets
Utility plant, at cost
Land	$	28,833		4,982		4,346		—	—	—		$	38,161
Plant and equipment		2,504,389		830,237		796,600		—	—	—			4,131,226
Less accumulated depreciation		(988,732	)	(324,517	)	(333,864	)	—	—	—			(1,647,113	)
Plant acquisition adjustment, net		—		—		41		—	—	—			41
Construction in progress		114,227		26,262		10,690		—	—	—			151,179

Net utility plant		1,658,717		536,964		477,813		—	—	—			2,673,494

Investment in wholly owned subsidiaries, at equity		410,911		—		—		—	—	(410,911	)		—

Current assets
Cash and equivalents		203		3,069		773		198	435	—			4,678
Advances to affiliates		36,600		—		2,000		—	—	(38,600	)		—
Customer accounts receivable, net		98,129		26,554		21,429		—	—	—			146,112
Accrued unbilled revenues, net		82,550		16,795		14,929		—	—	—			114,274
Other accounts receivable, net		6,657		2,481		3,025		—	—	(5,248	)		6,915
Fuel oil stock, at average cost		57,289		12,494		22,088		—	—	—			91,871
Materials & supplies, at average cost		15,723		4,404		14,131		—	—	—			34,258
Prepayments and other		6,946		1,239		1,305		—	—	—			9,490

Total current assets		304,097		67,036		79,680		198	435	(43,848	)		407,598

Other long-term assets
Regulatory assets		209,034		40,663		35,293		—	—	—			284,990
Unamortized debt expense		10,555		2,458		2,622		—	—	—			15,635
Other		30,449		5,671		6,051		—	—	—			42,171

Total other long-term assets		250,038		48,792		43,966		—	—	—			342,796

	$	2,623,763		652,792		601,459		198	435	(454,759	)	$	3,423,888

Capitalization and liabilities
Capitalization
Common stock equity	$	1,110,462		201,820		208,521		182	388	(410,911	)	$	1,110,462
Cumulative preferred stock–not subject to mandatory redemption		22,293		7,000		5,000		—	—	—			34,293
Long-term debt, net		567,657		145,811		171,631		—	—	—			885,099

Total capitalization		1,700,412		354,631		385,152		182	388	(410,911	)		2,029,854

Current liabilities
Short-term borrowings-nonaffiliates		28,791		—		—		—	—	—			28,791
Short-term borrowings-affiliate		2,000		36,600		—		—	—	(38,600	)		—
Accounts payable		97,699		21,810		18,386		—	—	—			137,895
Interest and preferred dividends payable		9,774		2,370		2,738		—	—	(163	)		14,719
Taxes accrued		119,032		35,380		35,225		—	—	—			189,637
Other		41,792		9,835		11,194		16	47	(5,085	)		57,799

Total current liabilities		299,088		105,995		67,543		16	47	(43,848	)		428,841

Deferred credits and other liabilities
Deferred income taxes		130,573		17,791		13,749		—	—	—			162,113
Regulatory liabilities		180,725		46,460		34,421		—	—	—			261,606
Unamortized tax credits		32,664		12,941		12,814		—	—	—			58,419
Other		103,876		51,972		27,470		—	—	—			183,318

Total deferred credits and other liabilities		447,838		129,164		88,454		—	—	—			665,456

Contributions in aid of construction		176,425		63,002		60,310		—	—	—			299,737

	$	2,623,763		652,792		601,459		198	435	(454,759	)	$	3,423,888

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Common Stock Equity (unaudited)

Nine months ended September 30, 2008


(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and eliminations		HECO consolidated
Balance, December 31, 2007	$	1,110,462		201,820		208,521		182		388		(410,911	)	$	1,110,462
Comprehensive income:
Net income (loss)		77,949		16,417		15,503		(54	)	(347	)	(31,519	)		77,949
Retirement benefit plans:
Amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes		4,099		569		464		—		—		(1,033	)		4,099
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory asset, net of taxes		(3,928	)	(554	)	(446	)	—		—		1,000			(3,928	)

Comprehensive income (loss)		78,120		16,432		15,521		(54	)	(347	)	(31,552	)		78,120

Common stock dividends		(14,088	)	—		(10,965	)	—		—		10,965			(14,088	)
Issuance of common stock		—		—		—		—		100		(100	)		—

Balance, September 30, 2008	$	1,174,494		218,252		213,077		128		141		(431,598	)	$	1,174,494

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Common Stock 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 (loss)		23,978		2,274		8,156		(58	)	(10,372	)		23,978
Retirement benefit plans - amortization of net loss, prior service cost and transition obligation included in net periodic benefit cost, net of tax benefits		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 D&O related to defined benefit plans, net of taxes		18,205		18,205		—		—		(18,205	)		18,205
Adjustment to initially apply FIN 48, net of tax benefits		(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 Cash Flows (unaudited)

Nine months ended September 30, 2008


(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and eliminations		HECO consolidated
Cash flows from operating activities
Income (loss) before preferred stock dividends of HECO	$	78,759		16,817		15,789		(54	)	(347	)	(32,205	)	$	78,759
Adjustments to reconcile income (loss) before preferred stock dividends of HECO to net cash provided by (used in) operating activities:
Equity in earnings		(31,594	)	—		—		—		—		31,519			(75	)
Common stock dividends received from subsidiaries		11,040		—		—		—		—		(10,965	)		75
Depreciation of property, plant and equipment		61,657		23,454		21,143		—		—		—			106,254
Other amortization		2,368		532		3,526		—		—		—			6,426
Deferred income taxes		6,244		1,939		(1,595	)	—		—		—			6,588
Tax credits, net		588		759		156		—		—		—			1,503
Allowance for equity funds used during construction		(4,957	)	(1,069	)	(406	)	—		—		—			(6,432	)
Changes in assets and liabilities:
Increase in accounts receivable		(40,569	)	(14,145	)	(12,140	)	—		—		7,303			(59,551	)
Increase in accrued unbilled revenues		(16,483	)	(3,242	)	(3,669	)	—		—		—			(23,394	)
Increase in fuel oil stock		(73,820	)	(3,702	)	(2,171	)	—		—		—			(79,693	)
Decrease (increase) in materials and supplies		(2,816	)	(637	)	18		—		—		—			(3,435	)
Decrease (increase) in regulatory assets		1,804		182		(2,014	)	—		—		—			(28	)
Increase (decrease) in accounts payable		37,035		13,550		(4,261	)	—		—		—			46,324
Change in prepaid and income accrued income and utility revenue taxes		(1,938	)	(1,684	)	(4,347	)	—		—		—			(7,969	)
Changes in other assets and liabilities		1,999		(4,899	)	4,865		(4	)	(44	)	(7,303	)		(5,386	)

Net cash provided by (used in) operating activities		29,317		27,855		14,894		(58	)	(391	)	(11,651	)		59,966

Cash flows from investing activities
Capital expenditures		(90,318	)	(56,692	)	(23,311	)	—		—		—			(170,321	)
Contributions in aid of construction		7,574		3,092		1,600		—		—		—			12,266
Advances from (to) affiliates		(39,550	)	—		2,000		—		—		37,550			—
Investment in consolidated subsidiary		(100	)	—		—		—		—		100			—
Other		862		—		—		—		(113	)	—			749

Net cash used in investing activities		(121,532	)	(53,600	)	(19,711	)	—		(113	)	37,650			(157,306	)

Cash flows from financing activities
Common stock dividends		(14,088	)	—		(10,965	)	—		—		10,965			(14,088	)
Preferred stock dividends		(810	)	(400	)	(286	)	—		—		686			(810	)
Proceeds from issuance of long-term debt		14,399		1,628		2,680		—		—		—			18,707
Proceeds from issuance of common stock		—		—		—		—		100		(100	)		—
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		110,204		23,550		16,000		—		—		(37,550	)		112,204
Decrease in cash overdraft		(8,581	)	—		(1	)	—		—		—			(8,582	)

Net cash provided by financing activities		101,124		24,778		7,428		—		100		(25,999	)		107,431

Net increase (decrease) in cash and equivalents		8,909		(967	)	2,611		(58	)	(404	)	—			10,091
Cash and equivalents, beginning of period		203		3,069		773		198		435		—			4,678

Cash and equivalents, end of period	$	9,112		2,102		3,384		140		31		—		$	14,769

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

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 Form 10-K for the year ended December 31, 2007 and should be read in conjunction with the annual (as of and for the year ended December 31, 2007) and quarterly (as of and for the three months ended March 31, 2008, and as of and for the three and six months ended June 30, 2008) consolidated financial statements of HEI and HECO and accompanying notes.

HEI CONSOLIDATED

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)	2008		2007		% change	Primary reason(s) for significant change *
Revenues	$	915,431	$	673,461	36	Increase for the electric utility segment, partly offset by decreases for the bank and “other” segments

Operating income		74,129		48,017	54	Increase for the electric utility and bank segments, partly offset by an increase in losses for the “other” segment

Net income		37,281		19,881	88	Higher operating income, higher AFUDC and slightly lower “interest expense—other than on deposit liabilities and other bank borrowings,” partly offset by higher taxes resulting from higher income before taxes and a higher effective income tax rate **

Basic earnings per common share	$	0.44	$	0.24	83	Higher net income

Weighted-average number of common shares outstanding		84,625		82,481	3	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)	2008		2007		% change	Primary reason(s) for significant change *
Revenues	$	2,419,103	$	1,828,247	32	Increase for the electric utility segment, partly offset by decreases for the bank and “other” segments

Operating income		166,477		121,867	37	Increase for the electric utility segment, partly offset by decrease for the bank segment (resulting from the impact of the balance sheet restructuring) and an increase in losses for the “other” segment

Net income		76,384		44,194	73	Higher operating income and AFUDC and lower “interest expense—other than on deposit liabilities and other bank borrowings,” partly offset by higher taxes resulting from higher income before taxes and a higher effective income tax rate **

Basic earnings per common share	$	0.91	$	0.54	69	Higher net income

Weighted-average number of common shares outstanding		84,052		81,949	3	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 rates (federal and state) for the third quarters of 2008 and 2007 were 35% and 34%, respectively. The Company’s effective tax rates for the first nine months of 2008 and 2007 were 35% and 34%, respectively. The effective tax rates were slightly lower in 2007 than in 2008 due primarily to state tax credits.

Dividends

On October 31, 2008, the HEI Board of Directors (Board) maintained the quarterly dividend of $0.31 per common share. The payout ratios for 2007 and the first nine months of 2008 were 120% and 102%, respectively. Excluding the net income impact ($35.6 million) of ASB’s balance sheet restructuring, the payout ratio for the first nine months of 2008 would have been 70%. HEI’s Board believes that HEI should have 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

As a consequence of deteriorating financial conditions within the banking industry, a series of events occurred in September and October 2008 that resulted in unprecedented global capital market volatility and decline. In September or October 2008, the U.S. government seized control of the Federal National Mortgage Association (Fannie Mae) and Federal Home Loan Mortgage Corporation (Freddie Mac), Lehman Brothers Holdings Inc. (Lehman) declared bankruptcy, Bank of America agreed to acquire Merrill Lynch & Co. Inc., the Federal Reserve Bank made an emergency loan to American International Group, Inc. (AIG), Barclays PLC agreed to acquire Lehman’s North American investment banking assets, the Federal Reserve approved of the Goldman, Sachs & Co. and Morgan Stanley & Co. Incorporated changes of status to bank holding companies, Washington Mutual Inc. was closed by the U.S. government in the largest failure of a U.S. bank (and its banking assets were sold to JPMorgan Chase & Co.), Wells Fargo’s plan to acquire Wachovia Corporation was approved, the Bush Administration’s initial $700 billion “bailout” bill was defeated in the U.S. House of Representatives (which led to the largest one-day point drop in history for the Dow Jones Industrials Average) and the Emergency Economic Stabilization Act of 2008 was signed into law (see below).

Management did not anticipate these events and the volatile capital and credit markets in its planning and forecasting. These events and the volatile markets have resulted in higher short-term borrowing costs, and have impacted or are expected to impact the Company’s retirement benefit plans significantly (e.g., assets, costs and funding requirements) for 2009 and future years (see “Retirement benefits” below). Although HEI and HECO are reevaluating their financing plans under current market conditions, at this time management does not expect these extraordinary events to have a material adverse impact on the Company’s or consolidated HECO’s liquidity, capital resources or results of operations for 2008. For example, both HEI and HECO currently have access to the commercial paper market (although commercial paper rates are higher than earlier in the year). However, if market conditions deteriorate further, the Company’s and HECO’s liquidity, capital availability and results of operations could be significantly impacted. Specific segment exposure is further detailed in the segment discussions of results, “Liquidity and capital resources” and “Retirement benefits.”

The Blue Chip economic consensus released on November 1, 2008 predicts real GDP growth will be marginally positive in 2009. All economists responding to the Blue Chip survey agree that the national economy has slipped into recession with most predicting that it will last longer than the recessions of 1990-1991 and 2001. Consumer confidence has been adversely affected and credit is largely unavailable, which in turn has and will continue to negatively impact consumer spending.

The price of a barrel of crude oil has fallen recently, with prices dropping from a peak of $145.29 per barrel on July 3, 2008 and closing at $64.15 per barrel on October 24, 2008. The skyrocketing cost of fuel oil over the summer pushed electricity bills higher, resulting in even greater customer conservation. As a result, in the third quarter of 2008 and into the fourth quarter of 2008, the utilities experienced sales declines. Although lower fuel prices are starting to show up in customers’ bills, the utilities expect continued conservation by customers and full year 2008 kilowatthour (KWH) sales to decrease at a level similar to the year-to-date September 2008 sales decline of 1.2% (compared to the same period last year), primarily because of the ailing national and Hawaii economies’ impact on consumer decisions. A similar downward trend is expected in 2009. The expected decline in sales will adversely impact the utilities’ and consolidated HEI’s fourth quarter 2008 and 2009 results of operations.

Short-term interest rates were very volatile during the third quarter of 2008 as a result of the volatility in the financial and credit markets. Additionally, credit concerns caused short-term Treasury rates to decline while causing short-term corporate borrowing rates to increase dramatically. ASB’s borrowing costs were not impacted by the increase in credit spreads because wholesale borrowing costs from the Federal Home Loan Bank did not experience a similar increase during the third quarter.

The turmoil in the financial markets and further declines in the national and global economies are having a negative effect on the Hawaii economy, with some state economists predicting recession. Weakness is most notable in one of the state’s largest industries, tourism. The closure of Aloha and ATA Airlines, departure of two Norwegian Cruise Line cruise ships from Hawaii, record-high oil prices and the downturn in the national economy have impacted the visitor industry. Visitor arrivals by air were down 15% in the third quarter of 2008 compared with the third quarter of last year and year-to-date through September 30, 2008 were down 9% compared with the same period last year. Arrivals for Kauai, Maui, Lanai and the Big Island were most affected with arrivals down on those islands by 18%, 14%, 12%, and 17%, respectively, for the nine months ended September 30, 2008 compared with the same period of 2007.

Visitor expenditures were $8.7 billion for the nine months ended September 30, 2008, down 7% compared with expenditures for the same period last year. For comparison purposes, visitor expenditures reached a record $12 billion for the full year 2006.

Hotel occupancies, another indicator of tourism sector health, are down, especially on Maui and the Big Island. Statewide figures show September 2008 occupancy rates at 63% compared with 74% for September 2007. September 2008 occupancy rates on Oahu were the highest in the state at 69.4% a 9.9 percentage point decline from September 2007. Rates for Maui and the Big Island declined more significantly. September 2008 occupancies for Maui, and the Big Island were 56.8% and 49.9%, respectively, representing percentage point declines from September 2007 of 14.8 and 9.5, respectively.

Local tourism authorities continue to increase marketing efforts in its base market, the western U.S., to help stimulate demand for travel. Current forecasts show full year visitor arrivals to be down 9% in 2008 and down 1% in 2009, with recovery delayed until 2010. However, with the national and global economies in decline, state economists may revise their expectations for visitor arrivals downward in the coming months.

In September 2008, median home prices on Oahu slipped just below the $600,000 mark and September 2008 year-to-date sales volumes continue to decline compared with volumes for the same period last year. Also in September 2008, Hawaii foreclosures rose significantly, especially on the neighbor islands.

Permitted construction (nongovernment) continues to slow due to increased costs and tighter credit conditions. However, slowing continues to be considerably more moderate than in many U.S. mainland markets. Private new residential construction in Hawaii is expected to decline in 2008 and 2009 before stabilizing in 2010. A new Disney resort development on Oahu will help permitted construction. Military projects and state infrastructure projects will also provide stability to the overall construction industry in Hawaii.

At 4.5%, seasonally-adjusted Hawaii unemployment at the end of September 2008 remains below the national average of 6.1%. Declines in tourism are expected to cause job losses to continue into next year. Total payroll jobs in Hawaii are expected to be flat in 2008, with a 0.8% decline in 2009. Growth of less than 1% is expected in 2010.

Overall, the Hawaii economy is starting to show signs of decline, but the magnitude and length of the decline cannot be predicted.

Emergency Economic Stabilization Act of 2008

The Emergency Economic Stabilization Act of 2008 (the 2008 Act) was signed into law on October 3, 2008. The principal parts of the 2008 Act are: 1) a $700 billion financial markets stabilization plan; and 2) $150 billion in tax benefits, which are partially offset by $40 billion in revenue raisers. As part of its energy and conservation related incentives, the 2008 Act allows public utility property to qualify for the energy credit for periods after February 13, 2008 and extends the credit for solar energy property, fuel cell property and microturbine property through December 31, 2016. In addition, the 2008 Act allows the credit for combined heat and power system property as energy property for periods after October 3, 2008. The 2008 Act also provides for 10-year accelerated

depreciation period for smart electric meters and smart electric grip equipment for property placed in service after October 3, 2008. The Company does not expect the tax provisions of the 2008 Act to have a material effect on results of operations for 2008. These tax provisions, however, may influence the Company’s future decisions to invest in the various properties entitled to credits. For example, in subsequent years, the utilities plan, consistent with the HCEI set forth in the Energy Agreement, to invest in smart meter technology for which the 2008 Act provides the favorable 10-year depreciable life. The Company will continue to analyze the impacts of the 2008 Act on its results of operations, financial condition and liquidity and for the opportunities it presents.

Retirement benefits

Based on various assumptions (in Note 8 of HEI’s “Notes to Consolidated Financial Statements” in HEI Exhibit 13 to HEI’s Current Report on Form 8-K dated February 21, 2008) and assuming no further changes in retirement benefit plan provisions, consolidated HEI’s, consolidated HECO’s and ASB’s retirement benefits expense (including amounts for the defined benefit, defined contribution and other postemployment benefit plans), net of income tax benefits, is estimated to be $19 million, $17 million and $1 million, respectively, in 2008, compared to actual expense, net of income tax benefits, of $20 million, $16 million and $2 million, respectively, in 2007. Also, see Notes 5 and 4 to HEI’s and HECO’s “Notes to Consolidated Financial Statements,” respectively.

Because of the significant decline in the value of plan assets through September 30, 2008, the Company expects that the minimum required contribution to the qualified retirement plans (after reduction for a credit balance) calculated in accordance with the Pension Protection Act and the expected timing of the cash requirement based on 1) the value of plan assets as of September 30, 2008 and 2) 80% of the value of plan assets as of September 30, 2008, will be as follows for plan years 2009 and 2010. The minimum required contribution may differ from the cash requirement for each plan year because the rules under the Internal Revenue Code allow the Company to make its last installment contribution as late as September of the following year. In addition, the Company is allowed to elect to apply any credit balance against the minimum required contribution. Further, the utilities have committed to fund their net periodic pension cost each year unless the minimum required contribution under ERISA and the Internal Revenue Code requires a greater contribution level. The “Cash funding requirement” in the following table reflects the utilities’ net periodic pension cost funding commitment (assuming a 7.125% discount rate).


(in millions)	2009		2010
Pension Protection Act minimum required contribution:
(after reduction for credit balances)
Assuming plan assets as of September 30, 2008
Consolidated HECO	$	21	$	56
Consolidated HEI		21		56
Assuming 80% of the value of plan assets as of September 30, 2008
Consolidated HECO		46		83
Consolidated HEI		46		84

Cash funding requirement:
Assuming plan assets as of September 30, 2008
Consolidated HECO		6		59
Consolidated HEI		6		59
Assuming 80% of the value of plan assets as of September 30, 2008
Consolidated HECO		12		98
Consolidated HEI		12		100

“Other” segment


(in thousands)	Three months ended September 30						% change	Primary reason(s) for significant change
(in thousands)	2008			2007			% change	Primary reason(s) for significant change
Revenues	$	(32	)	$	339		NM	Third quarter 2007: leveraged lease investment income and unrealized gains on venture capital investments Third quarter 2008: unrealized losses on venture capital investments

Operating loss		(2,410	)		(1,896	)	NM	See explanation for revenues and higher labor expense (including executive incentive compensation), partly offset by lower consulting expense

Net loss		(4,056	)		(4,725	)	NM	See explanation for operating loss, offset by lower interest expense


(in thousands)	Nine months ended September 30						% change	Primary reason(s) for significant change
(in thousands)	2008			2007			% change	Primary reason(s) for significant change
Revenues	$	(164	)	$	2,749		NM	First nine months of 2007: gain on the sale of Hoku shares of $1.4 million, leveraged lease investment income and gain of $0.9 million and unrealized gains on venture capital investments First nine months of 2008: unrealized losses on venture capital investments

Operating loss		(8,812	)		(7,949	)	NM	See explanation for revenues and higher labor expense (including executive incentive compensation), partly offset by lower consulting expense

Net loss		(13,453	)		(15,693	)	NM	See explanation for operating loss, offset by lower interest expense and tax adjustments

NM Not meaningful.

The “other” business segment includes results of operations of HEI Investments, Inc. (HEIII), a company previously holding investments in leveraged leases; Pacific Energy Conservation Services, Inc., a contract services company primarily providing wind farm operational and maintenance services to an affiliated electric utility; HEI Properties, Inc., 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. Since HEIII sold all of its leveraged lease investments by the end of 2007, HEIII has filed articles of dissolution and is winding up its affairs.

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

Despite the recent unprecedented deterioration in the capital markets and tightening of credit, the Company believes that its ability to generate cash, both internally from electric utility and banking operations and externally from issuances of equity and debt securities, commercial paper and bank borrowings, is adequate to maintain sufficient liquidity to fund its contractual obligations and commercial commitments, its forecasted capital expenditures and investments, its expected retirement benefit plan contributions 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, 2008				December 31, 2007
Short-term borrowings—other than bank	$	231	8	%	$	92	4	%
Long-term debt, net—other than bank		1,211	44			1,242	47
Preferred stock of subsidiaries		34	1			34	1
Common stock equity		1,321	47			1,275	48

	$	2,797	100	%	$	2,643	100	%

As of October 31, 2008, 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
Senior unsecured debt	BBB	Baa2

The above ratings reflect only the view of the applicable rating agency at the time the ratings are issued, from whom an explanation of the significance of such ratings may be obtained. Such 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 and Moody’s outlook for HEI is “stable.”

The rating agencies use a combination of qualitative measures (i.e., assessment of business risk that incorporates an analysis of the qualitative factors such as management, competitive positioning, operations, markets and regulation) as well as quantitative measures (e.g., cash flow, debt, interest coverage and liquidity ratios) in determining the ratings of HEI securities. In May 2008, S&P affirmed its corporate credit ratings and “stable” outlook of HEI. S&P’s ratings outlook “assesses the potential direction of a long-term credit rating over the intermediate term (typically six months to two years).” S&P stated:

Unsupportive or lagged rate treatment or changes in the current fuel adjustment clause of the company that would result in erosion of key financial parameters, especially cash flow coverage of debt, would be cause for change in the current ratings and/or a negative outlook. A severe slump in the state economy could also contribute to downward rating pressure. Given these challenges, higher ratings are not foreseen during the outlook horizon and would need to be accompanied by sustained and improved financial performance.

S&P designates business risk profiles as “excellent,” “strong,” “satisfactory,” “weak” or “vulnerable.” S&P stated in May 2008 that: “HEI’s business profile is strong, reflecting a degree of diversification afforded by American’s banking business, which features a reasonably solid lending portfolio that is not expected to be adversely affected by the subprime crisis, and the generally stable, regulated utility assets of HEI’s three utilities. The consolidated business profile’s strengths are tempered by the reliance of both businesses on Hawaii’s economy, which is dependent on a limited number of industries for growth.”

S&P’s financial risk designations are “minimal,” “modest,” “intermediate,” “aggressive” and “highly leveraged.” In May 2008, S&P indicated that “[t]he consolidated financial profile is aggressive, reflecting in part the very heavy debt imputation we apply to the three utilities for power purchase agreements (PPA).”

In June 2008, Moody’s issued an Issuer Comment regarding ASB’s balance sheet restructuring. Moody’s viewed the Company’s announcement that ASB had substantially completed the balance sheet restructuring “as being positive to HEI’s credit quality, but not material enough to warrant a rating change or a change in the company’s stable outlook.” In September 2008, Moody’s affirmed its credit ratings and “stable” outlook for HEI. Moody’s stated, “[t]he rating could be downgraded should weaker than expected economic growth and regulatory support emerge at HECO which ultimately causes earnings and sustainable cash flows to suffer over an extended period.” Consequently, Moody’s indicated that a shift in its expectations regarding the company’s future sustainable levels of consolidated financial ratios such as Funds From Operations (net cash flow from operations less net changes in working capital items) to Adjusted Debt below 16% (16% as of June 30, 2008 – latest reported by Moody’s) or Funds From Operations to Adjusted Interest of less than 3.5x (3.9x as of June 30, 2008 – latest reported by Moody’s) could result in a lowering of the Company’s rating.

See the electric utilities’ and bank’s respective “Liquidity and capital resources” sections below for the ratings of HECO and ASB.

Information about the Company’s short-term borrowings and HEI’s line of credit facility was as follows:


	Nine months ended September 30, 2008				December 31, 2007
(in millions)	Average balance		End-of-period balance		December 31, 2007
Short-term borrowings
HEI commercial paper	$	92	$	50	$	63
HEI line of credit draws		—		40		—
HECO commercial paper		77		141		29

	$	169	$	231	$	92

Line of credit facility (expiring March 31, 2011)¹			$	100	$	100
Undrawn capacity under HEI’s line of credit facility²				60		100

¹	In the future, 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.

²	Amount has not been reduced by HEI commercial paper outstanding, which is backed by the line of credit facility. At October 31, 2008, the outstanding commercial paper balance was $6 million and the amount undrawn under the line of credit facility was $39 million.

HEI utilizes short-term debt, typically commercial paper, to support normal operations, to refinance commercial paper, to retire long-term debt 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. Due to the recent credit market conditions resulting in a tightening commercial paper market, limited maturity options and escalating commercial paper rates, HEI drew $40 million (with a one month duration) of its $100 million syndicated line of credit facility, rather than issuing commercial paper, in late September 2008. When it matured, this $40 million was refinanced through a two-week draw on the credit facility. On October 3, 2008, HEI drew an additional $21 million (with a 35 day duration) on the credit facility to fund commercial paper maturities and limit its exposure in the commercial paper markets. When it matures, HEI plans to refinance this $21 million draw through another draw on the credit facility. All other short-term funding needs (including the funding of commercial paper maturities) have been funded by commercial paper sales. HEI intends to continue to refinance its remaining commercial paper maturities with commercial paper sales, market conditions permitting. Management believes that, if HEI’s commercial paper ratings were to be downgraded or if credit markets further tighten, it would be more difficult and expensive to sell commercial paper or it might not be able to sell commercial paper in the future.

As of September 30, 2008, $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. Under SEC regulations, these two registrations will expire or be terminated by November 30, 2008. After the filing of this report on Form 10-Q, HEI plans to file a new omnibus registration statement to register an indeterminate amount of debt, equity and hybrid securities. Under SEC regulations, this new registration statement, when filed, would expire in three years.

For the first nine months of 2008, net cash provided by operating activities of consolidated HEI was $74 million. Net cash provided by investing activities and net cash used in financing activities for the same period were $1.2 billion and $1.2 billion, respectively, primarily due to ASB’s balance sheet restructuring in June 2008. Net cash provided by investing activities included ASB’s proceeds from the sale of investment and mortgage-related securities of $1.3 billion and repayments of investment and mortgage-related securities of $0.5 billion, partly offset by ASB’s purchases of investment and mortgage-related securities of $0.4 billion and HECO’s consolidated capital expenditures of $0.2 billion. Net cash used in financing activities included net decreases in ASB’s other borrowings of $1.1 billion, ASB’s deposit liabilities of $165 million and long-term debt of $31 million and the payment of common stock dividends of $62 million, partly offset by a net increase in short-term borrowings of $139 million.

Forecasted HEI consolidated “net cash used in investing activities” (excluding “investing” cash flows from ASB) for 2008 through 2010 consists primarily of the net capital expenditures of HECO and its subsidiaries. In addition to the funds required for the electric utilities’ construction program, $50 million was required in March 2008 to repay maturing HEI medium-term notes, which were repaid with the proceeds from the issuance of commercial paper. Additional debt and/or equity financing may be utilized to pay down commercial paper or other short-term borrowings or may be required to fund unanticipated expenditures not included in the 2008 through 2010 forecast, such as increases in the costs of or an acceleration of the construction of capital projects of the utilities, utility capital expenditures that may be required by the Hawaii Clean Energy Initiative or new environmental laws and regulations, unbudgeted acquisitions or investments in new businesses, significant increases in retirement benefit funding requirements and higher tax payments that would result if tax positions taken by the Company do not prevail. In addition, existing debt may be refinanced prior to maturity (potentially at more favorable rates) with additional debt or equity financing (or both). HEI is currently considering an equity financing, depending on market conditions, and HECO and its electric utility subsidiaries recently filed an application with the PUC for approval of one or more special purpose revenue bond financings (with the first such financing anticipated to be in 2009).

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 12 to 13, 36 to 40, and 47 to 49 of HEI’s MD&A which is incorporated into Part II, Item 7 of HEI’s 2007 Form 10-K by reference to HEI Exhibit 13 to HEI’s Current Report on Form 8-K dated February 21, 2008.

Additional factors that may affect future results and financial condition are described on pages iv and v under “Forward-Looking Statements” and pages 81 to 82 under “Risk Factors.”

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 13 to 14, 40 to 41, and 49 of HEI’s MD&A which is incorporated into Part II, Item 7 of HEI’s 2007 Form 10-K by reference to HEI Exhibit 13 to HEI’s Current Report on Form 8-K dated February 21, 2008.

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

ELECTRIC UTILITIES

Executive overview and strategy—recent development

On October 20, 2008, the Governor of the State of Hawaii, the State of Hawaii Department of Business, Economic Development and Tourism, the Division of Consumer Advocacy of the State of Hawaii Department of Commerce and Consumer Affairs, and HECO, on behalf of itself and its subsidiaries, HELCO and MECO (collectively, the parties), signed an Energy Agreement setting forth the goals and objectives of a Hawaii Clean Energy Initiative (HCEI) and the related commitments of the parties (the agreement). The agreement provides that the parties pursue a wide range of actions, many of which will require PUC approval, with the purpose of decreasing the State of Hawaii’s dependence on imported fossil fuels through substantial increases in the use of renewable energy and implementation of new programs intended to secure greater energy efficiency and conservation. A few of the major provisions of the agreement directly affecting HECO and its subsidiaries, which may be subject to PUC approval, are: (1) pursuing an overall goal of providing 70% of Hawaii’s electricity and ground transportation energy needs from clean energy sources; (2) establishing a Clean Energy Infrastructure Surcharge (CEIS) designed to expedite cost recovery for infrastructure that supports greater use of renewable energy or grid efficiency within the utility systems; (3) pursuing the integration of approximately 1,100 MW from a variety of renewable energy sources into the utility systems, including a proposed 400 MW wind farm to supply power to Oahu from Lanai or Molokai through a yet-to-be constructed undersea transmission cable system; (4) developing a feed-in tariff system with standardized purchase prices for renewable energy; and (5) adopting a new regulatory rate-making model, which employs a revenue adjustment mechanism that tracks the difference between the amount of revenues allowed in the last rate case and the sum of the current costs of providing electric service and a reasonable return on, and return of, additional capital investment in the electric system. See “Hawaii Clean Energy Initiative (HCEI)” in Note 5 of HECO’s “Notes to Consolidated Financial Statements” for a more detailed discussion of the agreement and HECO Exhibit 10.12 for a copy of the agreement.

RESULTS OF OPERATIONS


(dollars in thousands, except per barrel amounts)	Three months ended September 30				%		Primary reason(s) for significant change
(dollars in thousands, except per barrel amounts)	2008		2007		change		Primary reason(s) for significant change
Revenues	$	827,788	$	567,615	46		Higher fuel oil and purchased energy fuel costs, the effects of which are generally passed on to customers ($248 million), interim rate relief ($21 million), a reserve accrual in 2007 for the refund of a portion of HECO’s 2005 test year rate increase ($15 million) and higher amounts of DSM costs recovered through a surcharge ($3 million), partly offset by 2.6% lower sales ($18 million) and proceeds from the sale of non-electric utility property in 2007 ($5 million)
Expenses
Fuel oil		377,157		222,721	69		Higher fuel oil costs, partially offset by less KWHs generated

Purchased power		202,125		144,918	39		Higher fuel costs and KWHs purchased

Other		196,659		168,610	17		Higher other operation and maintenance (O&M) ($4 million), depreciation expenses ($1 million) and taxes, other than income taxes ($23 million)

Operating income		51,847		31,366	65		Interim rate relief and 2007 accrual of a reserve for a portion of HECO’s 2005 test year rate increase, partly offset by a gain on sale of non-electric utility property in 2007 and higher other O&M and depreciation expenses

Net income		25,932		12,875	101		Higher operating income and AFUDC, partly offset by higher interest and income tax expenses

Kilowatthour sales (millions)		2,593		2,663	(3	)	Customer conservation, DSM activities, slowing economic activity and cooler weather on Oahu
Cooling degree days (Oahu)		1,530		1,566	(2	)
Average fuel oil cost per barrel	$	133.99	$	74.78	79


(dollars in thousands, except per barrel amounts)	Nine months ended September 30				%
(dollars in thousands, except per barrel amounts)	2008		2007		change		Primary reason(s) for significant change
Revenues	$	2,139,798	$	1,508,005	42		Higher fuel oil and purchased energy fuel costs, the effects of which are generally passed on to customers ($559 million), interim rate relief ($67 million), a reserve accrual in 2007 for the refund of a portion of HECO’s 2005 test year rate increase ($15 million) and higher amounts of DSM costs recovered through a surcharge ($9 million), partly offset by lower KWH sales ($20 million) and proceeds from the sale of non-electric utility property in 2007 ($5 million)
Expenses
Fuel oil		900,455		549,771	64		Higher fuel oil costs, partly offset by less KWHs generated

Purchased power		530,146		390,161	36		Higher fuel costs and KWHs purchased

Other		550,971		494,926	11		Higher other O&M ($9 million), depreciation expenses ($3 million), and taxes, other than income taxes ($55 million), partly offset by the write-off of HELCO plant in service in 2007 ($12 million)

Operating income		158,226		73,147	116		Interim rate relief, 2007 accrual of a reserve for a refund of a portion of HECO’s 2005 test year rate increase and 2007 write-off of a portion of HELCO’s CT-4 and CT-5, partly offset by higher other O&M expenses, a gain on sale of non-electric utility property in 2007 and higher depreciation expense

Net income		77,949		23,978	225		Higher operating income and AFUDC, partly offset by higher interest and income tax expenses

Kilowatthour sales (millions)		7,478		7,568	(1	)	Customer conservation, DSM activities and slowing economic activity, partly offset by warmer weather on Oahu
Cooling degree days (Oahu)		3,779		3,666	3
Average fuel oil cost per barrel	$	111.37	$	65.52	70

Note: The electric utilities’ effective tax rates (federal and state) for the first nine months of 2008 and 2007 were 37% and 34%, respectively. The first nine months of 2007 reflect the acceleration of state tax credits associated with the write-off of a portion of CT-4 and CT-5 and the effect of utilizing state tax credits against a significantly lower income tax expense base.

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

Results – three months ended September 30, 2008

Operating income for the third quarter of 2008 increased 65% from the same period in 2007 due primarily to $21 million of interim rate relief granted by the PUC to HECO (2007 test year) and MECO (2007 test year) in October 2007 and December 2007, respectively. Kilowatthour (KWH) sales in the third quarter of 2008 decreased 2.6% from the same period in 2007, primarily due to the impact of customer conservation efforts and DSM activities, slowing economic activity and cooler weather on Oahu. Cooling degree days for Honolulu (on the island of Oahu) were 2.3% lower in the third quarter of 2008 when compared to the same period in 2007.

Other operation expenses for the third quarter increased $7.5 million, or 14%, primarily due to higher DSM expenses that are generally passed on to customers through a surcharge ($2.7 million), administrative and general expenses ($1.9 million) and production operations expenses ($1.2 million). In spite of a 12.5 basis points higher discount rate assumption, pension and other postretirement benefit expenses for the electric utilities were comparable to the same period in 2007 primarily due to the adoption of the pension tracking mechanisms, including amortization of HELCO’s prepaid pension asset (approved on an interim basis by the PUC; see “Most recent rate requests”). Maintenance expenses for the third quarter of 2008 decreased by $3.4 million, or 12%, primarily due to lower production maintenance expenses (primarily due to $2.4 million of lower costs related to the lower scope and timing of generating unit overhauls) and lower generating station maintenance. Higher depreciation expense ($1.1 million) was attributable to additions to plant in service in 2007.

Other O&M expenses for the third quarter of 2008 increased by 5% over the same quarter in 2007. The expected increase in full year 2008 other O&M expenses continues to be roughly 6% over 2007, but actual levels could be influenced by a number of factors that cannot be predicted. The electric utilities expect higher DSM expenses (that are generally passed on to customers through a surcharge, including additional expenses for programs that have been approved in an energy efficiency DSM Docket), higher production expenses, primarily due to increased utilization of HECO’s generating assets commensurate with the level of demand that has occurred over the past 5 years, and higher costs for materials and contract services. In addition, the costs of environmental compliance continue to increase with changes to the law and more stringent regulatory requirements and additional costs are expected to be incurred to execute the provisions of the Energy Agreement.

As a result of load growth on Oahu and other factors, there currently is an increased risk to generation reliability at least until HECO installs its planned new generating unit in 2009. Generation reserve margins on Oahu continued to be strained. HECO has taken a number of steps to mitigate the risk of outages, including securing additional purchased power, adding distributed generation at some substations and encouraging energy conservation. The marginal costs of supplying energy to meet growing demand, however, are increasing because of the tight peak reserve margin situation, and the trend of cost increases is not likely to ease.

Results – nine months ended September 30, 2008

Operating income for the first nine months of 2008 increased 116% from the same period in 2007 due primarily to $67 million of interim rate relief granted by the PUC and a write-off in the first quarter of 2007 of a portion of plant-in-service costs related to CT-4 and CT-5 (see “Most recent rate cases”). KWH sales in the nine months ended September 30, 2008 decreased 1.2% from the same period in 2007, primarily due to the impact of customer conservation efforts and DSM activities and slowing economic activity, partially offset by warmer weather on Oahu and the impact of an additional leap year day in February 2008. Cooling degree days for Honolulu (on the island of Oahu) were 3.1% higher in the first nine months of 2008 when compared to the same period in 2007.

Other operation expenses for the first nine months of 2008 increased $21.7 million, or 14%, primarily due to higher DSM expenses that are generally passed on to customers through a surcharge ($8.0 million), administrative and general expenses ($5.2 million) and production operation expenses ($4.4 million). Maintenance expenses for the nine months ended September 30, 2008 decreased by $13.0 million, or 15%, primarily due to lower production maintenance expenses (primarily due to $10.8 million of lower costs related to the lower scope and timing of generating unit overhauls) and lower transmission and distribution maintenance expenses (primarily due to $1.2 million of lower costs related to substation maintenance). Higher depreciation expense ($3.4 million) was attributable to additions to plant in service in 2007.

Renewable energy strategy

The electric utilities have been taking actions intended to protect Hawaii’s island ecology and counter global warming, while continuing to provide reliable power to customers, and recently committed to a number of related actions in the Energy Agreement entered into with the State. A three-pronged strategy supports attainment of the requirements and goals of the State of Hawaii RPS, the Hawaii Global Warming Solutions Act of 2007 and the HCEI 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, and additional ones have been committed to in the Energy Agreement.

In its June 27, 2008 filing with the PUC, HECO reported a consolidated RPS of 16.1% in 2007. This was accomplished through a combination of municipal solid waste, geothermal, wind, biomass, hydro, photovoltaic and biodiesel renewable generation resources; renewable energy displacement technologies; and energy savings from efficiency technologies.

The electric utilities are actively exploring the use of biofuels for existing and planned company-owned 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 its steam generating units from fossil fuels to biofuels, and in the Energy Agreement has committed to do so if economically and technically feasible and if adequate biofuels are available.

In January 2007, HECO and MECO agreed to form a venture with BlueEarth Biofuels LLC (BlueEarth) to develop a biodiesel production facility on MECO property in Wa’ena on the island of Maui. BlueEarth Maui Biofuels LLC (BlueEarth Maui), a joint venture to pursue biodiesel development, was recently formed between BlueEarth and Uluwehiokama Biofuels Corp. (UBC), a non-regulated subsidiary of HECO. In February 2008, an Operating Agreement and an Investment Agreement were executed between BlueEarth and UBC, under which UBC invested $400,000 in BlueEarth Maui in exchange for a minority ownership interest. 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 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. MECO has been negotiating with BlueEarth Maui for a fuel purchase contract for biodiesel to be used in existing diesel-fired units at MECO’s Maalaea plant. Both the land 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, which focuses on sustainable palm oil and locally-grown feedstocks, to ensure that the project would procure biofuel and biofuel feedstocks only from sustainable sources. Recently, BlueEarth’s and MECO’s negotiations for the biodiesel supply contract stalled based on an inability to reach agreement on various financial and risk allocation issues. In October 2008, BlueEarth filed an action in federal district court in Texas against MECO, HECO and others alleging claims based on the parties’ failure to have reached agreement on the biodiesel supply and land agreements. The lawsuit seeks unspecified damages and equitable relief. The parties are currently exploring the possibility of amicably resolving their disputes and the litigation.

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). In November 2007, HECO entered into a contract to purchase energy from a photovoltaic system with a generating capacity of up to 300 kilowatts to be located at HECO’s Archer substation. The PUC approved the contract in May 2008. In October 2008, the PUC approved a power purchase contract between MECO and Lanai Sustainability Research, LLC for the purchase of 1.2 MW of electricity from a photovoltaic system owned by Lanai Sustainability Research, LLC. In September 2007, HECO issued a Solicitation of Interest for its planned Renewable Energy Request for Proposals (RFP) for combined renewable energy projects up to 100 MW on Oahu. In June 2008, the PUC approved HECO’s Oahu Renewable Energy RFP and HECO issued the RFP shortly thereafter. HECO received bids representing a variety of renewable technologies and a short list of bids proceeding to the Interconnection Requirements Study phase is expected to be identified by December 31, 2008. Included in the bids received were proposals for large scale neighbor island wind projects. In accordance with the Energy Agreement, these proposals for large scale neighbor island wind projects will be bifurcated from the Oahu Renewable Energy RFP. This bifurcated RFP process to evaluate and select the most appropriate Big Wind project or projects will be led by HECO with support from the State of Hawaii. The process to bifurcate the RFP is currently being developed by HECO with the assistance of outside consultants and will be conducted in general conformance with the competitive bidding framework. HECO plans to review this process with the PUC.

HECO’s unregulated subsidiary, Renewable Hawaii, Inc. (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 memoranda of understanding and conditional investment agreements with project developers, no investments have been made to date.

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

Energy efficiency and DSM 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. Since the inception of the energy efficiency and DSM programs in 1996 and through the end of 2007, the total system peak load has been reduced by 118 MW (100 MW at HECO, 7 MW at HELCO, and 11 MW at MECO) at the gross generation level and net of estimated reductions from participants who would have installed the DSM measure without the program and rebate.

For a description of some of the major provisions of the Energy Agreement most directly affecting HECO and its subsidiaries and their commitments relating to renewable energy and energy efficiency, see “Hawaii Clean Energy Initiative (HCEI)” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.”

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

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.

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. For a description of some of the regulatory changes that will be pursued as part of the Energy Agreement, see “Hawaii Clean Energy Initiative (HCEI)” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.”

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. In December 2006, the PUC issued a decision that included a final competitive bidding framework, which became effective immediately. In 2007, the PUC approved the utilities’ 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 Code of Conduct.

In June 2008, HECO issued a RFP, which seeks proposals for the supply of up to approximately 100 MW of long-term renewable energy for the island of Oahu under a power purchase agreement. Bids were received in September 2008 and a short list of bidders is expected to be identified by December 2008. The Energy Agreement recognized that the Oahu Renewable Energy RFP provides an excellent near-term opportunity to add new clean renewable energy sources on Oahu and included the anticipated up to 100 MW of renewable energy from these project proposals in its goals. See “Renewable energy strategy” above for a discussion on the bifurcation of the large-scale neighbor island wind project proposals from the Oahu Renewable Energy RFP.

In December 2007, in response to MECO’s request for approval to proceed with a competitive bidding process to acquire two separate increments of approximately 20 MW to 25 MW of firm generating capacity on the island of Maui in the 2011 and 2015 timeframes (which timeframes have since been revised and are now estimated to be 2014 and 2016 respectively), the PUC issued an order opening a new docket to receive filings, review approval requests, and resolve disputes, if necessary, related to MECO’s proposed RFP. The order identified MECO and the Consumer Advocate as parties to this new docket and approved MECO’s contract with the Independent Observer for the proposed RFP. Competitive bidding activities for the firm capacity increment identified for the 2014 timeframe are expected to begin in 2009. The schedule for the start of competitive bidding activities for the firm capacity increment targeted for the 2016 timeframe is under review.

In May 2008, the PUC issued a D&O stating that PGV’s proposal to modify its existing PPA with HELCO to provide an additional 8 MW of firm capacity by expanding its existing facility is exempt from the Competitive Bidding Framework. In the third quarter 2008, the PUC granted requests for waivers from the Competitive Bidding

Framework for two biomass projects (one on Maui and one on the island of Hawaii), a wind/hydroelectric project (on the island of Hawaii), and a wind/battery energy storage project (on the island of Hawaii), all subject to the submittal of a fully executed term sheet within four months of the decision granting the waiver, and documentation showing the fairness of the price being included in the application for approval of a power purchase agreement. The utilities have filed one other application for waiver from the Competitive Bidding Framework for a project on the island of Hawaii, a decision on which is pending.

In September 2008, HECO submitted fully executed term sheets for the following three renewable energy projects, “grandfathered” from the competitive bidding process: a Honua Power steam turbine generator, a Kahuku Wind Power wind farm, and a Sea Solar Power, International ocean thermal energy conversion project. In October 2008, timelines for the completion and execution of the power purchase contracts and the planned in-service dates for these three projects were submitted to the PUC.

Management cannot currently predict the ultimate effect of these developments on the ability of the 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 indicating 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. The D&O affirmed the ability of the 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. The PUC found that the “disadvantages outweigh the advantages” of allowing a utility to provide DG services on a customer’s site. 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 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 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 utilities are developing or evaluating potential DG projects. In September 2008, HECO executed an agreement with the State of Hawaii Department of Transportation to develop a dispatchable standby generation (DSG) facility at the Honolulu Airport that will be owned by the State and operated by HECO. The D&O encouraged HECO to pursue such DG operating arrangements with customers. HECO will file an application to the PUC for approval of the agreement in the fourth quarter 2008.

HECO is also evaluating the potential to develop utility-owned DG at Oahu military bases, in a manner consistent with the D&O, in order to meet utility system needs and the energy objectives of the Department of Defense. HECO also plans to conduct a feasibility review of extending the use of temporary DG units that were installed at various HECO substations in 2005 to 2007, and converting them to run on biodiesel.

In February 2008, MECO received PUC approval of an agreement for the installation of a CHP system at a hotel site on the island of Lanai. Final engineering for the project is in progress and the CHP system is planned to be placed in service in mid-2009.

The January 2006 D&O also required the utilities to file tariffs and establish standby rates based on unbundled costs associated with providing each service (i.e., generation, distribution, transmission and ancillary services). The 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. See “Distributed generation tariff proceeding” below.

Distributed generation tariff proceeding. In December 2006, the PUC opened a new proceeding to investigate the utilities’ proposed DG interconnection tariff modifications and standby rate tariffs. In March 2008, the parties to the proceeding filed a settlement agreement with the PUC that a standby service tariff agreed to by the parties should be approved. The interconnection tariffs, with modifications made in response to the PUC’s information requests, were approved in April 2008. In May 2008, the PUC approved the settlement agreement on the standby service tariff.

Under the Energy Agreement, the utilities will conduct a review of the modified DG interconnection tariffs by June 30, 2009, judging whether the tariffs are effective in supporting non-utility DG and distributed energy storage by improving the process and procedure for interconnection.

DG and Distributed Energy Storage (DES) under the Energy Agreement. Under the Energy Agreement, the utilities will facilitate planning for distributed energy resources through a new Clean Energy Scenario Planning process. Under this process, Locational Value Maps will be developed by December 31, 2009 to identify areas where DG and DES would provide utility system benefits and can be reasonably accommodated.

The utilities also agreed to power utility-owned DG using sustainable biofuels or other renewable technologies and fuels, and to support DES either customer-owned or utility-owned. HECO will also conduct a review of its DG interconnection tariffs by June 30, 2009. See “Distributed generation tariff proceeding” above.

The parties to the Energy Agreement support reconsideration of the PUC’s restrictions on utility-owned DG where it is proven that utility ownership and dispatch clearly benefits grid reliability and ratepayer interests, and the equipment is competitively procured. The parties also support HECO’s dispatchable standby generation (DSG) units upon showing reasonable ratepayer benefits.

The utilities may contract with third parties to aggregate fleets of DG or standby generators for utility dispatch or under power purchase agreements, or may undertake such aggregation itself if no third parties respond to a solicitation for such services.

The Energy Agreement also provides that to the degree that transmission and distribution automation and other smart grid technology investments are needed to facilitate distributed energy resource utilization, those investments will be recovered through a Clean Energy Infrastructure Surcharge and later placed in rate base in the next rate case proceeding.

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

As of October 31, 2008, the ROACE found by the PUC to be reasonable in the most recent final rate decision for each utility was 10.7% for HECO (D&O issued on May 1, 2008, based on a 2005 test year), 11.5% 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 in the interim rate increases in HECO,

HELCO and MECO rate cases based on 2007, 2006 and 2007 test years issued in October, April and December 2007, respectively, were 10.7%.

For the 12 months ended September 30, 2008, the actual ROACEs (calculated under the rate-making method, which excludes the effects of items not included in determining electric utility rates, and reported to the PUC) for HECO, HELCO and MECO were 10.21%, 10.94% and 9.49%, respectively. MECO’s actual ROACE was 145 basis points lower than its authorized ROACE primarily due to the timing of the interim rate relief for its 2007 test year rate case and increased O&M expenses, which are expected to continue. The interim rate relief granted to the utilities by the PUC (see below) in their most recent cases was based in part on increased costs of operating and maintaining their systems, and the gap between allowed and actual ROACEs has been narrowing as interim rate relief has become effective.

As of October 31, 2008, the ROR found by the PUC to be reasonable in the most recent final rate decision for each utility was 8.66% for HECO, 9.14% for HELCO and 8.83% for MECO (D&Os noted above). The RORs used by the PUC for purposes of the interim D&Os in the HECO, HELCO and MECO rate cases based on 2007, 2006 and 2007 test years were 8.62%, 8.33% and 8.67%, respectively. For the 12 months ended September 30, 2008, the actual RORs (calculated under the rate-making method, which excludes the effects of items not included in determining electric utility rates, and reported to the PUC) for HECO, HELCO and MECO were 7.65%, 8.25% and 7.37%, respectively.

In 2007, HECO, HELCO and MECO received interim D&Os in their most recent rate cases, which included the reclassification to a regulatory asset of the charge for retirement benefits that would otherwise be recorded in accumulated other comprehensive income (AOCI).

For a description of some of the rate-making changes that the parties have agreed to pursue under the Energy Agreement, see “Hawaii Clean Energy Initiative (HCEI)” in Note 5 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, based on a 2005 test year, a 9.11% ROR and an 11.5% ROACE. Disregarding an amount included in the request to transfer the cost of existing DSM programs from a surcharge line item on electric bills into base electricity charges, the requested base rates increase was $74 million, or 7.3%.

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. The 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, authorizing an increase of $53 million ($41 million net additional revenues). 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).

On October 25, 2007, the PUC issued an amended proposed final D&O, authorizing a net increase of 2.7%, or $34 million, in annual revenues, based on a 10.7% ROACE (and an 8.66% ROR on a rate base of $1.060 billion). The amended proposed final D&O, which has now been issued in final form with certain modifications (as described below), reversed 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 required a refund 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 through July 19, 2008, was approximately $1.8 million, which amount was reserved for the refund and included an adjustment for the interest synchronization method adopted by the PUC (as proposed by the DOD in its filed exception to the proposed final D&O).

of $45 million in annual revenues ($34 million net) based on a 10.7% ROACE (and an 8.66% ROR on a rate base of $1.060 billion). In the final D&O, the PUC accepted the parties’ position that the review of the ECAC under Act 162 would be made in HECO’s 2007 test year rate case. See Note 8 of HECO’s “Notes to Consolidated Financial Statements.” Following the issuance of the final D&O, the required refund, with interest, to customers was completed in August 2008. On October 2, 2008, HECO filed with the PUC its 2005 test year rate case refund reconciliation, which reflected an actual customer refund amount of $18.2 million compared to the target refund of $16.8 million. HECO also filed tariff sheets to collect the over-refunded amount of $1.4 million from customers, effective November 1 through November 30, 2008. On October 28, 2008, the PUC issued a letter stating that HECO’s refund plan, approved on June 20, 2008, did not include a reverse-refund mechanism, thus, HECO was not authorized to collect the $1.4 million over-refunded amount. As a result of the letter, HECO reduced its revenues for the third quarter of 2008 by $1.4 million for the amounts over-refunded.

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., over rates that included 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. 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 2006 application included 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 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 requested 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 had earlier 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, but that request was denied. HECO thus proposed in the 2007 test year 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. HECO’s position was that, if the reduction in equity balance resulting from the AOCI charges is not restored for ratemaking purposes, a higher ROACE will be required.

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

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. For a discussion of this mechanism and related pension issues, see Note 8, “Retirement Benefits” of HEI’s “Notes to Consolidated Financial Statements.”

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 $70 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, an ROACE of 10.7% (and an 8.62% ROR 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 indicated that the amount of the stipulated interim rate increase would be adjusted to take into account any such changes. For purposes of the settlement, the parties agreed to a pension tracking mechanism that does not include amortization of HECO’s pension asset (comprised of accumulated contributions to its pension plan in excess of net periodic pension cost and amounting to $68 million at December 31, 2006) as part of the pension tracking mechanism in the proceeding. (This has the effect of deferring the issue of whether the pension asset should be amortized for rate making purposes to HECO’s next rate case.)

In accordance with Act 162 (Hawaii Revised Statutes §269-16(g)), the PUC, by an order issued August 24, 2007, had added as an issue to be addressed in the rate case whether HECO’s ECAC complies with the requirements of Act 162. 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 $70 million in annual revenues over rates effective at the time of the interim D&O, subject to refund with interest. The interim increase is based on the settlement agreement described above and did not include in rate base the HECO pension asset. The interim D&O also approves, on an interim basis, the adoption of the pension tracking mechanism and a tracking mechanism for OPEB. See “Interim increases” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.”

On May 1, 2008, the PUC issued the final D&O for HECO’s 2005 test year rate case, which was consistent with the stipulated revised results of operations filed by the parties on March 28, 2008. Consistent with the previous settlement agreement with the parties in this case, HECO filed a motion with the PUC in May 2008 to adjust the amount of the annual interim increase in this proceeding from $70 million to $77.9 million to take into account the changes in current effective rates as a result of the final decision in the 2005 test year rate case, and to have the change be effective at the same time the tariff sheets reflecting the final decision in the 2005 rate case become effective. In June 2008, the PUC approved HECO’s motion. On September 30, 2008, HECO filed a correction with the PUC to adjust the amount of the annual interim increase for the 2007 test year rate case from $77.9 million to $77.5 million and filed tariff sheets to be effective October 1 through 31, 2008 to refund $0.1 million over-collected from June 20 to September 30, 2008.

Management cannot predict the timing, or the ultimate outcome, of a final D&O in HECO’s 2007 test year rate case.

2009 test year rate case. On July 3, 2008, HECO filed a request for a general rate increase of $97 million or 5.2% over the electric rates currently in effect (i.e., over rates that included the interim rate increase discussed above granted by the PUC in HECO’s 2007 test year rate case, which amount is $77 million based on the final decision in HECO’s 2005 test year rate case), based on a 2009 test year, an 8.81% ROR, an 11.25% ROACE, and a $1.408 billion rate base. HECO’s application requested an interim increase of $73 million on or before the statutory deadline for interim rate relief and a step increase of $24 million based on the return on net investment of the new

combustion turbine generating unit at Campbell Industrial Park and recovery of associated expenses to be effective at the in-service date of the new unit, scheduled for the end of July 2009.

The requested rate increase will support anticipated plant additions of $375 million in 2008 and 2009 (including $162 million for the new generating unit and related transmission line) to maintain and improve system reliability, higher operation and maintenance costs required for HECO’s electrical system, and higher depreciation expenses since the last rate case. As in its 2007 test year rate case, HECO requests continuation of its ECAC in its present form.

The request excludes incremental DSM costs from the test year revenue requirement due to the transition of HECO’s DSM programs to a third-party program administrator in 2009 as ordered by the PUC.

In August 2008, the PUC granted the DOD’s motion to intervene in the rate case proceeding. In September 2008, the PUC held a public hearing on HECO’s rate increase application.

In the Energy Agreement, the parties agree to seek approval from the PUC to implement in the interim decision in the 2009 HECO rate case a decoupling mechanism, similar to that in place for several California utilities, which decouples revenue of the utilities from KWH sales and provides revenue adjustments for the differences between the amount determined in the last rate case and (a) the current cost of operating the utility as deemed reasonable and approved by the PUC, (b) return on and returns of ongoing capital investment (excluding projects included in a proposed new Clean Energy Infrastructure Surcharge), and (c) changes in State or Federal tax rates. The decoupling mechanism would be subject to review at anytime by the PUC or upon the request of the utility or Consumer Advocate.

Management cannot predict the timing, or the ultimate outcome, of an interim or final D&O.

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 included 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. 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. In July 2008, HELCO submitted responses to information requests from the PUC regarding the impacts of passing changes in fuel and purchased energy costs to customers through the ECAC.

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 and the Consumer Advocate reached settlement agreements on all revenue requirement issues in the HELCO 2006 rate case proceeding, which were documented in an April 5, 2007 settlement letter. 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 by tariff changes made effective 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 an ROR of 8.33% (incorporating an ROACE of 10.7%). In the interim D&O, the PUC also approved on an interim basis the adoption of pension and OPEB tracking mechanisms.

Pursuant to an agreed upon schedule of proceedings, Keahole Defense Coalition filed a response to HELCO’s rebuttal testimony on April 28, 2007, to which HELCO responded on May 11, 2007. On May 15, 2007, HELCO and the Consumer Advocate filed a settlement letter that reflected their agreement on the remaining rate design issues in the proceeding. HELCO and the Consumer Advocate filed their opening briefs in support of their settlement on June 4, 2007 and agreed not to file reply briefs. In April 2008, HELCO and the Consumer Advocate filed a supplement providing additional record cites and supporting information relevant to their April 2007 settlement letter.

Management cannot predict the timing, or the ultimate outcome, of a final D&O.

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 requested 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 proposed 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%. $4.75 million of the $9.4 million difference between MECO’s and the Consumer Advocate’s proposed increase is caused by the Consumer Advocate’s lower recommended ROR and ROACE.

On December 7, 2007, MECO and the Consumer Advocate (for purposes of this section, the “Parties”) reached a settlement of all the revenue requirement issues in this rate case proceeding. For purposes of the settlement agreement, the parties agreed that MECO’s energy cost adjustment clause provides a fair sharing of the risks of fuel cost changes between MECO and its ratepayers and no further changes are required for MECO’s energy adjustment clause to comply with the requirements of Act 162.

On December 21, 2007, the PUC issued an interim D&O granting MECO an increase of $13.2 million in annual revenues, or a 3.7% increase, subject to refund with interest. The interim increase is based on the settlement agreement, which included, as a negotiated compromise of the Parties’ respective positions, an increase of $13.2 million in annual revenue, a 10.7% ROACE, an 8.67% ROR and a rate base of $383 million (which did not include MECO’s pension asset, which amounted to $1 million as of December 31, 2007).

In the interim D&O, the PUC also approved on an interim basis the adoption of pension and OPEB tracking mechanisms.

Management cannot predict the timing, or the ultimate outcome, of a final D&O.

Anticipated HELCO and MECO 2009 test year rate cases. In order to implement the decoupling mechanism committed to by the parties in the Energy Agreement, the parties agreed in the Energy Agreement that HELCO and MECO will each file a 2009 test year rate case.

Other regulatory matters. See “Hawaii Clean Energy Initiative (HCEI)” and “Major projects” in Note 5 of HECO’s “Notes to Consolidated Financial Statements” for a number of actions committed to in the Energy Agreement that will require PUC approval in either pending or new PUC proceedings.

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 program 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 “[u]pon selection of the PBF Administrator, the PUC intends, in this docket, to determine whether the electric utilities will be allowed to compete for the implementation of the Energy Efficiency DSM programs.” The PUC has issued a draft RFP for the PBF Administrator. In July 2008, the PUC issued an Order to Initiate the Collection of Funds for the PBF Administrator of Energy Efficiency Programs, which authorized the electric utilities to expense $50,000 per quarter beginning July 1, 2008 for the initial start-up costs associated with the PBF Administrator and recover the cost in the DSM surcharge; confirmed that the load management, SolarSaver and RCEA programs shall remain with the electric utilities; directed the electric utilities to continue to operate the DSM programs through June 30, 2009, and after the transition period, the electric utilities can compete for implementation of DSM programs as a subcontractor.

The EE Docket 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 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. In 2007, HECO recorded incentives of $4 million. HELCO and MECO proposed goals for their programs, based on the goals established for HECO’s programs, but recorded no incentives in 2007. In June 2008, the PUC issued an order approving MECO’s proposed cumulative energy and demand savings goals for 2007 and 2008, but set MECO’s annual incentive cap at $320,000. Thus, in the second quarter of 2008, MECO recorded an incentive of $320,000 related to 2007. A decision on HELCO’s proposed goals is pending. The utilities’ DSM incentives for 2008 are subject to adjustment based on the results of impact evaluation reports and may be lower than 2007 incentives. Additionally, in October 2008, HECO requested the PUC to authorize higher 2008 DSM incentive budgets. If approval of these higher budgets is not received, it could result in lower 2008 incentives.

Unlike the EE DSM programs, load management DSM programs will continue to be administered by the utilities. HECO’s 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 or central air conditioning systems 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. This program includes small business direct load control and voluntary program elements.

In April 2008, HECO filed an application for approval of a Dynamic Pricing Pilot Program and for recovery of the incremental costs of the program through the DSM Adjustment component of the IRP Cost Recovery

Provision. Dynamic pricing is a type of demand response program that allows prices to change from normal tariff rates as system conditions change and encourages customer curtailment of load through price incentives when there is insufficient generation to meet a projected peak demand period. The proposed pilot will run for approximately one year and will test the effect of a demand response program on a sample of residential customers.

Avoided cost generic docket. In May 1992, the PUC instituted a generic investigation 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. In March 1994, the parties to the docket entered into a Stipulation to Resolve Proceeding, which was subject to PUC approval. In December 2006, the parties filed an updated stipulation 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. In March 2008, the PUC issued an order which approved the updated stipulation and ordered that the new avoided energy cost rates and Schedule Q rates will go into effect on August 1, 2008. HECO, HELCO and MECO filed new avoided energy costs rates and Schedule Q rates, which were determined using the new “resource-in / resource-out” methodology instead of the proxy method. These rates are effective from August 1 through December 31, 2008, and the fuel component of the rates will adjust monthly for changes in fuel prices.

On October 1, 2008, HECO, HELCO and MECO filed preliminary avoided energy costs rates and Schedule Q rates to be effective for 2009. The PUC initiated a docket to examine the methodology for calculating Schedule Q electricity payment rates in the State of Hawaii. The proceeding is intended to examine new methodologies for calculating Schedule Q payment rates, with the intent of removing or reducing any linkages between the price of fossil fuels and the rate for non-fossil fuel generated electricity. The parties to the Energy Agreement agree that all new renewable energy contracts are to be delinked from fossil fuel and that the utilities will seek to renegotiate existing PPAs with independent power producers that are based on fossil fuel prices to delink their energy payment rates from oil costs. Based on this understanding, the parties agree to request that the PUC suspend the pending Schedule Q proceeding for a period of 12 months with a view to reviewing the necessity of the docket.

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 were 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), HECO (since September 2005) and MECO (since December 2007) now recover IRP costs (which are included in O&M) through base rates. Previously, HECO, HELCO and MECO recovered their costs through a surcharge. The Consumer Advocate has objected to the recovery of $1.5 million (before interest) of the $4.3 million of incremental IRP costs incurred by the utilities during the 2000-2006 period, and the PUC’s decisions are pending on these costs. Also, see Note 5 in HECO’s “Notes to Consolidated Financial Statements” and “Demand-side management programs” above.

The parties to the Energy Agreement agree to seek to replace the current IRP process with a new Clean Energy Scenario Planning (CESP) process, described in the Energy Agreement, intended to be used to determine future investments in transmission, distribution and generation that will be necessary to facilitate high levels of renewable energy production. The parties commit to supporting reasonable and prudent investment in the ongoing maintenance and upgrade of the existing generation, transmission and distribution systems, unless the CESP process determines otherwise.

HECO’s IRP. On September 30, 2008, HECO filed its fourth IRP (IRP-4) covering a 20-year (2009-2028) planning horizon, subject to PUC approval. The IRP-4 preferred plan calls for all future generation to be renewable. In addition, it calls for conversion of a number of existing HECO-owned generating units to utilize biofuels and for continued aggressive implementation of demand-side management programs. In addition to the 110 MW biofueled combustion turbine (CT) scheduled for installation by HECO in 2009, HECO plans to pursue the installation of a 100 MW biofueled CT at its Campbell Industrial Park generating station in the 2011-2012 timeframe and plans to submit to the PUC a request for a waiver from the competitive bidding process to install this increment of additional firm capacity. The addition of two simple cycle CTs will add to the system additional fast starting and ramping capability, which will facilitate integration of as-available generation (such as wind and solar) to the system. HECO also plans to remove Waiau Unit 3, a 46 MW oil-fired cycling unit, from service after the second combustion turbine is in service, and will later determine whether to place the unit in emergency reserve status or to retire the unit. In 2009, HECO will conduct a test on Kahe Unit 3 to evaluate the use of Low Sulfur Fuel Oil/biofuel blends in existing oil-fired steam units. Other renewable generation will be acquired via three renewable energy projects “grandfathered” from competitive bidding and from projects that are selected from proposals submitted in response to HECO’s 100 MW RFP for Non-Firm Energy (see “Competitive bidding proceeding” above). On October 2, 2008, the PUC issued an order setting the issues, procedures and schedule for the IRP-4 docket. Among other activities, a public meeting is scheduled for December 3, 2008, and an evidentiary hearing is scheduled in March 2009.

In the Energy Agreement, the parties agree that the PUC will be asked to close the IRP-4 docket, suspend the HELCO and MECO IRP-4 dockets and open a new docket to establish the proposed CESP described in the Energy Agreement. In addition, the parties agree that HECO shall request PUC approval to implement items in the Action Plan that otherwise require approval through the IRP-4 process and, pending the D&O establishing the CESP process, HECO, HELCO and MECO will continue to meet with their Advisory Committees and file annual updates to their respective IRPs.

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 “Major projects” 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. In November 2007, HELCO and the Consumer Advocate filed a stipulated agreement which recommended that the PUC approve HELCO’s IRP-3 and in which HELCO agreed to make improvements to the IRP process and to submit evaluation reports by March 31, 2009 and March 31, 2010. In January 2008, the PUC issued its D&O approving HELCO’s IRP-3 and required HELCO to submit annual evaluation reports by March 31, 2009 and March 31, 2010 and file its IRP-4 by May 31, 2010.

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 on Maui 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. In July 2008, the PUC approved MECO’s IRP-3 and directed MECO to submit evaluation reports by December 31, 2008 and December 31, 2009, to make various improvements to the IRP process and to submit its IRP-4 by April 30, 2010.

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 written notice by either party of not less than two years. 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. In June 2008, MECO developed a new sales and peak forecast, which projects lower sales and peaks compared to the previous, July 2007, forecast. In July 2008, MECO filed an update to its 2008 Adequacy of Supply letter in which it indicated that the date the next increment of additional firm generating capacity on Maui is needed has changed from 2011 to 2014.

HECO’s 2009 Campbell Industrial Park generating unit. See “Campbell Industrial Park (CIP) generating unit” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.”

Adequacy of supply.

HECO. HECO’s 2008 Adequacy of Supply (AOS) letter, filed in January 2008, indicates that HECO’s analysis estimates its reserve capacity shortfall to be approximately 80 MW in the 2008 to 2009 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 reported in its 2008 AOS letter that it anticipates the potential for continued reserve capacity shortfalls could range between 20 MW to 80 MW in 2010, up to a range of 70 MW to 130 MW in 2014, 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 seek additional firm capacity is required to proceed under the guidance of the Competitive Bidding Framework issued by the PUC in December 2006. On September 30, 2008, HECO submitted to the PUC its IRP-4, which noted that a short-term sales and peak forecast was developed in March 2008. Analysis indicated that the reserve capacity shortfall could range from 0 MW to 20 MW in 2011 and from 50 MW to 80 MW in 2014. As stated earlier (see “HECO’s IRP” above), HECO plans to pursue the installation of a second 100 MW biofueled combustion turbine at its Campbell Industrial Park generating station in the 2011-2012 timeframe. HECO also plans to remove a 46 MW oil-fired cycling unit from service after the second combustion turbine is in service, and will later determine whether to place the unit in emergency reserve status or to retire the unit.

HECO’s gross peak demand was 1,327 MW in 2004, 1,273 MW in 2005, 1,315 MW in 2006 and 1,261 MW in 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 2008 Adequacy of Supply letter filed in January 2008 indicated that HELCO’s generation capacity for the next three years, 2008 through 2010, is sufficiently large to meet all reasonably expected demands for service and provide reasonable reserves for emergencies.

MECO. MECO’s 2008 Adequacy of Supply letter filed in January 2008 indicated that MECO’s generation capacity for the next three years, 2008 through 2010, is sufficient to meet the forecasted demands on the islands of Maui, Lanai and Molokai. Although MECO may not at times have sufficient capacity on the Maui system to cover for the

loss of the largest unit, MECO will implement appropriate mitigation measures to overcome any reserve capacity situations.

In July 2008, MECO filed an update to its 2008 Adequacy of Supply letter in which it indicated that the date the next increment of additional firm generating capacity on Maui is needed has changed from 2011 to 2014, due primarily to a reduction in the forecast of peak demand.

On occasions in 2006 and 2007, MECO experienced lower than normal generation capacity due to the unexpected temporary losses of several of its generating units, and issued public requests that its customers voluntarily conserve electricity.

October 2006 outages. 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, and brought 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 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 a docket to examine the feasibility of implementing intra-governmental wheeling of electricity in the State of Hawaii. The issues in the proceeding adopted 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, (7) addressing how rates would be set, (8) identifying the environmental impacts, (9) identifying and evaluating the various forms of intra-governmental wheeling and (10) identifying and evaluating the resulting impact to any and all governmental entities, including but not limited to economic, feasibility and liability impacts. Parties to this proceeding include HECO, HELCO, MECO, Kauai Island Utility Cooperative and the Consumer Advocate, as well as governmental agencies (the DOD, the DBEDT, the City and County of Honolulu and the Counties of Hawaii, Maui and Kauai), an environmental group, and two renewable energy developers. Two renewable energy contractors and a renewable energy developer also have been granted more limited participant status. The procedural schedule includes technical workshops and meetings through December 2008, with a formal process to commence thereafter.

As part of the Energy Agreement, the PUC will be requested to suspend the pending intra-governmental wheeling docket for a period of 12 months while the parties evaluate the necessity of the docket in view of the other agreements of the parties.

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. Also see “Hawaii Clean Energy Initiative (HCEI)” and “Environmental regulation” in Note 5 of HECO’s “Notes to Consolidated Financial Statements” and “Emergency Economic Stabilization Act of 2008” above.

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. No funds have been appropriated to date. 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. Hawaii has a RPS law requiring electric utilities to meet an RPS 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 the electric utilities attained a RPS of 11.7%. It may be difficult, however, for the electric utilities to attain required RPS 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 provides 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 RPS law also provides 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 law directed that the PUC, by December 31, 2007, develop and implement a utility ratemaking structure 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.

The Energy Agreement includes a provision to seek legislation to revise the RPS law to require electric utilities to meet an RPS of 25% by 2020 and 40% by 2030. In addition, the Energy Agreement includes a provision to eliminate energy efficiency and conservation as contributors to the RPS targets after 2014. Furthermore, the Energy Agreement includes a provision that imported biofuel generation cannot account for more than 30% of the RPS target through 2015.

In January 2007, the PUC opened a new docket (RPS Docket) to examine Hawaii’s RPS law, to establish the appropriate penalties for failure to meet RPS targets and to determine the circumstances under which penalties should be levied. In December 2007, the PUC issued a decision and order approving a stipulated RPS framework to govern electric utilities’ compliance with the RPS law. The PUC also directed the parties to file supplemental briefs regarding: (1) the reasonable range of penalties (in $/MWh) to include in the framework, (2) whether RPS non-compliance penalties should be paid into a special fund or to the State of Hawaii and (3) whether electric utilities should be expressly prohibited from recovering RPS non-compliance penalties through electric rates. Supplemental briefs and reply briefs have been filed.

In its December 2007 decision and order, the PUC deferred the RPS incentive framework to a new generic docket (Renewable Energy Infrastructure Program or REIP Docket). The Renewable Energy Infrastructure Program proposed by HECO 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 parties to the REIP Docket include the electric utilities, the Consumer Advocate, an environmental organization and Hawaii Renewable Energy Alliance (HREA). Public hearings were held in May 2008. In July 2008, statements of position were filed with the PUC, in which the Consumer Advocate recommended approval of, HREA supported, and the environmental organization did not oppose the REIP proposed by HECO. In October 2008, pursuant to the PUC’s request, the parties to the docket informed the PUC, among other things, that the parties (1) have reached an agreement on all of the issues in the docket, (2) agree that it is appropriate that the PUC approve the utilities’ proposed REIP and related REIP surcharge, (3) agree that the record in the proceeding is complete and ready for PUC decision-making, and (4) waive an evidentiary hearing.

In the Energy Agreement, the parties agreed that the REIP may be modified to incorporate changes for the CEIS mechanism, provided the appropriate notices to the public regarding the changes are made.

Management cannot predict the outcome of these processes.

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).

In 2005, the Legislature 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 kilowatts (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 (KIUC), the Consumer Advocate, a renewable energy organization and a solar vendor organization. In March 2008, the PUC approved a stipulated agreement filed by the parties (except for KIUC, which has its own 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, to reserve a certain percentage of the 1.0% system peak demand for generators 10 kw or less and to consider in the

IRP process any further increases in the maximum capacity of customer-generators and the system cap. The PUC further required the utilities: (1) to consider specific items relating to net energy metering in their respective IRP processes, (2) to evaluate the economic effects of net energy metering in future rate case proceedings and (3) to design and propose a net energy metering pilot program for the PUC’s review and approval that will allow, on a trial basis, the use of a limited number of larger generating units (i.e., at least 100kw to 500kw, and may allow for larger units) for net energy metering purposes.

In April 2008, the electric utilities filed a proposed four-year net energy metering pilot program to evaluate the effects on the grid of units larger than the currently approved maximum size. The program will consist of analytical investigations and field testing and is designed for a limited number of participants that own (or lease from a third party) and operate a solar, wind, biomass, or hydroelectric generator, or a hybrid system. The electric utilities propose to recover program costs through the IRP cost recovery provision.

In 2008, the net energy metering law was again amended to authorize the PUC in its discretion, by rule or order, to modify the maximum size of the eligible net metered systems and evaluate on an island-by-island basis whether to exempt an island or utility grid system from the total rated generating capacity limits available for net energy metering.

Pursuant to the Energy Agreement, the parties will seek to remove system-wide caps on net energy metering. Instead, they will seek to limit DG interconnections on a per circuit basis and to replace net energy metering with an appropriate feed-in tariff and new net metered installations that incorporate time-of-use metering equipment for future full scale implementation of time-of-use metering and sale of excess energy.

DSM programs. See “Demand-side management programs” above.

Non-fossil fuel purchased power contracts. In 2006, a law was enacted that 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, which 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 electric utilities are participating in the Task Force, as well as in initiatives aimed at reducing their GHG emissions, such as those to be undertaken under the Energy Agreement. 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 the EPA’s position, the EPA has the authority to regulate greenhouse gases under the Clean Air Act. Since then, the EPA has denied a California request for a waiver under the Clean Air Act to allow control of greenhouse gas emissions from motor vehicles, but has announced its intention to commence rulemaking to address greenhouse gas emissions. Although several bills addressing greenhouse gas emission reductions also have been introduced in Congress, none has yet been adopted. Accordingly, it is too early to assess the ultimate impact of the ruling.

On July 11, 2008, the EPA issued its Advance Notice of Proposed Rulemaking (ANPR) inviting public comment on the benefits and ramifications of regulating GHGs under the Clean Air Act (CAA or Act). The ANPR is one of the steps the EPA has taken in response to the U.S. Supreme Court’s decision in Massachusetts v. EPA, in which the Court found that the CAA authorizes the EPA to regulate tailpipe GHG emissions if the EPA determines they cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. The ANPR reflects the EPA’s assessment of the complexity and magnitude of the question of whether and how

GHGs could be effectively controlled under the CAA. Because the CAA language authorizing regulation of tailpipe emissions is virtually identical to the Act’s language regarding stationary source emissions, such as those emitted from the electric utilities’ facilities, the utilities have begun their review of the ANPR in order to determine whether to make comments, which are due by November 28, 2008.

Renewable energy. In 2007, a law was enacted that stated 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.

In 2008, a law was enacted to promote and encourage the use of solar thermal energy. This measure will require the installation of solar thermal water heaters in residences constructed after January 1, 2010, but allow for limited variances in cases where installation of solar water heating is deemed inappropriate. The measure will establish standards for quality and performance of such systems. Also in 2008, a law was enacted that is intended to facilitate the permitting of larger (200 MW or greater) renewable energy projects. The Energy Agreement includes several undertakings by the utilities to integrate solar energy into their electric grid.

Biofuels. In 2007, a law was enacted with the stated purpose of encouraging further production and use of biofuels in Hawaii. It established that biofuel processing facilities in Hawaii are a permitted use in designated agricultural districts and established a program with the Hawaii Department of Agriculture to encourage the production in Hawaii of energy feedstock (i.e., raw materials for biofuels).

In 2008, a law was enacted that encourages the development of biofuels by authorizing the Hawaii Board of Land and Natural Resources to lease public lands to growers or producers of plant and animal material used for the production of biofuels.

The utilities have agreed in the Energy Agreement to test the use of biofuels in their generating units and, if economically feasible, to connect them to the use of biofuels. For its part, the State agrees to support this testing and conversion by expediting all necessary approvals and permitting. The Energy Agreement recognizes that, if such conversion is possible, HECO’s requirements for biofuels would encourage the development of a local biofuels industry.

At this time, it is not possible to predict with certainty the impact of the foregoing legislation or legislation that is, or may in the future be, proposed.

Other developments

Advanced Meter Infrastructure (AMI). HECO has continued to evaluate two-way wireless technologies for utility applications through ongoing field tests of a pilot AMI system. The AMI system uses two-way Sensus Metering Systems’ FlexNet technology to communicate with 7,700 advanced meters at both residential and commercial customer sites. AMI technology enables automated meter reading, time-of-use pricing and conservation options for HECO customers. Other utility applications being evaluated include distribution system line monitoring and water heater and air conditioning load control for improved reliability for residential and commercial customers. Pursuant to the Energy Agreement, HECO will file an application with the PUC for approval of the installation of Advanced Metering Infrastructure (see “Hawaii Clean Energy Initiative (HCEI)” in Note 5 of HECO’s “Notes to Consolidated Financial Statements” for further details).

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

Despite the recent unprecedented deterioration in the capital markets and tightening of credit, 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 was as follows as of the dates indicated:


(in millions)	September 30, 2008				December 31, 2007
Short-term borrowings	$	141	6	%	$	29	1	%
Long-term debt		904	40			885	43
Preferred stock		34	2			34	2
Common stock equity		1,174	52			1,110	54

	$	2,253	100	%	$	2,058	100	%

As of October 31, 2008, the S&P and Moody’s ratings of HECO securities were as follows:


	S&P		Moody’s
Commercial paper	A-2		P-2
Special purpose revenue bonds (principal amount noted in parentheses, senior unsecured, insured as follows):
Ambac Assurance Corporation ($0.2 billion)	AA		Aa3
Financial Guaranty Insurance Company ($0.3 billion)	BBB	*	Baa1	*
MBIA Insurance Corporation ($0.3 billion)	AA		A2
Syncora Guarantee Inc. (formerly XL Capital Assurance Inc.) ($0.1 billion)	BBB	*	Baa1	*
HECO-obligated preferred securities of trust subsidiary	BB+		Baa2
Cumulative preferred stock (selected series)	Not rated		Baa3

* As a result of downgrades, Financial Guaranty Insurance Company’s (FGIC’s) and Syncora Guarantee Inc.’s (Syncora’s) (formerly XL Capital Assurance Inc.’s) current financial strength ratings by S&P are BB and BBB-, respectively, and their insurance financial strength ratings by Moody’s are B1 and Caa1, respectively. The revenue bonds insured by FGIC and Syncora referenced in the table above reflect a rating which corresponds to HECO’s senior unsecured debt rating by S&P, and HECO’s issuer rating by Moody’s, because those ratings are higher than those of the applicable bond insurer.

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 2008, S&P affirmed its ratings for HECO and indicated a stable outlook. 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).” In May 2008, S&P stated:

S&P designates business risk profiles as “excellent,” “strong,” “satisfactory,” “weak” or “vulnerable.” S&P stated in May 2008 that: “HECO’s strong business profile reflects stable, regulated utility assets of all three utilities, which serve about 95% of Hawaii’s population.”

In September 2008, Moody’s maintained its ratings and stable outlook for HECO. 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 flows to suffer.” To that end, if the utilities’ financial ratios declined on a permanent basis such that the Adjusted Cash Flow (net cash flow from operations less net changes in working capital items) to Adjusted Debt fell below 17% (20% as of June 30, 2008-latest reported by Moody’s) or Adjusted Cash Flow to Adjusted Interest declined to less than 3.6x (4.9x as of June 30, 2008-latest reported by Moody’s) for an extended period, the rating could be lowered.

Information about HECO’s short-term borrowings, HECO’s line of credit facility and special purpose revenue bonds (SPRBs) was as follows:


	Nine months ended September 30, 2008				December 31, 2007
(in millions)	Average balance		End-of-period balance		December 31, 2007
Short-term borrowings
Commercial paper	$	77	$	141	$	29

Line of credit facility (expiring March 31, 2011)¹				175		175
Undrawn capacity under line of credit facility²				175		175

Special purpose revenue bonds available for issue
2005 legislative authorization (expiring June 30, 2010)-HELCO			$	20	$	20
2007 legislative authorization (expiring June 30, 2012)
HECO				260		260
HELCO				115		115
MECO				25		25

Total special purpose revenue bonds available for issue			$	420	$	420

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. HECO is currently negotiating a new short-term syndicated credit facility, however, management cannot predict the timing and/or ultimate outcome of the negotiations.

²	Amount has not been reduced by HECO commercial paper outstanding, which is backed by the line of credit facility. At October 31, 2008, the outstanding commercial paper balance was $120 million and the amount undrawn under the line of credit facility was $175 million.

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. Management believes that, if HECO’s commercial paper ratings were to be downgraded or if credit markets further tighten, it would be more difficult and expensive to sell commercial paper or it might not be able to sell commercial paper in the future.

Revenue bonds are issued by the Department of Budget and Finance of the State of Hawaii to finance capital improvement projects of HECO and its subsidiaries, but the source of their repayment are the unsecured obligations of HECO and its subsidiaries under loan agreements and notes issued to the Department, including HECO’s guarantees of its subsidiaries’ obligations. The payment of principal and interest due on all revenue bonds currently outstanding are insured either by Ambac Assurance Corporation (Ambac), Financial Guaranty Insurance Company (FGIC), MBIA Insurance Corporation (MBIA) or Syncora Guarantee Inc. (Syncora) (formerly XL Capital Assurance, Inc.). The currently outstanding revenue bonds were initially issued with S&P and Moody’s ratings of AAA and Aaa, respectively, based on the ratings at the time of issuance of the applicable bond insurer. In 2008, however, ratings of Ambac, MBIA, FGIC and XLCA (now Syncora) were downgraded by S&P and Moody’s resulting in a downgrade of the bond ratings of all of the bonds as shown in the ratings table above. S&P and/or Moody’s ratings of Ambac, FGIC, MBIA and Syncora are reported to be on watch, review and/or negative

outlook. Management believes that if HECO’s ratings were to be downgraded, or if credit markets further tighten, it could be more difficult and/or expensive to sell bonds in the future.

Operating activities provided $60 million in net cash during the first nine months of 2008. Investing activities during the same period used net cash of $157 million primarily for capital expenditures, net of contributions in aid of construction. Financing activities for the same period provided net cash of $107 million, primarily due to an $112 million net increase in short-term borrowings and drawdown of $19 million in SPRBs, partly offset by the payment of $15 million of common and preferred dividends and $9 million decrease in cash overdraft.

As part of HECO’s 2009 test year rate case filing, HECO’s financing cost was based in part on forecast gross capital expenditures of $205 million in 2009. The $205 million reflects a $33 million increase from the estimate of gross capital expenditures for 2009 included in the previous five-year (2008-2012) consolidated utility forecast of $1.3 billion, as a result of further review of investments needed for infrastructure reliability. The five-year forecast of capital expenditures for HECO, HELCO and MECO are expected to be affected by the Energy Agreement, but these effects have not yet been quantified by management.

The PUC must approve issuances, if any, of equity and long-term debt securities by HECO, HELCO and MECO. Recently, HECO, MECO and HELCO filed with the PUC an application for approval of one or more special purpose revenue bond financings under the 2007 legislative authorization identified above, with the first such financing anticipated to be in 2009 if the PUC approves the application and market conditions are satisfactory.

BANK

RESULTS OF OPERATIONS


(in thousands)	Three months ended September 30				% change		Primary reason(s) for significant change
(in thousands)	2008		2007		% change		Primary reason(s) for significant change
Revenues	$	87,675	$	105,507	(17	)	Lower interest and noninterest income

Operating income		24,692		18,547	33		Higher net interest income and lower noninterest expense, partly offset by lower noninterest income

Net income		15,405		11,731	31		See operating income (loss) above, partly offset by higher income taxes

(in thousands)	Nine months ended September 30				% change		Primary reason(s) for significant change
(in thousands)	2008		2007		% change		Primary reason(s) for significant change
Revenues	$	279,469	$	317,493	(12	)	Lower interest and noninterest income, including a $19 million loss on the sale of securities related to the balance sheet restructure

Operating income		17,063		56,669	(70	)	Higher noninterest expense (including a $40 million loss on the early extinguishment of debt related to the balance sheet restructure) and lower noninterest income, partly offset by higher net interest income

Net income		11,888		35,909	(67	)	See operating income (loss) above, partly offset by lower income taxes

See “Results — three months ended September 30, 2008” and “Results — nine months ended September 30, 2008” for more detailed explanations of significant changes.

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

Net interest margin and other factors

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. The current interest rate environment is very volatile due to disruptions in the financial markets and may have a negative impact on ASB’s net interest margin.

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, 2008, ASB’s loan portfolio mix, net, consisted of 72% residential loans, 13% commercial loans, 7% commercial real estate loans and 8% consumer loans. As of December 31, 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 September 30, 2008, ASB-originated residential loans represented approximately 94% of the residential loan portfolio. All of the ASB-originated residential loans are located in the state of Hawaii, with approximately 66% of the loans located on the island of Oahu. At origination, approximately 70% of the ASB-originated loans had FICO scores greater than 700 and over 70% of the ASB-originated loans had loan-to-values less than or equal to 80%. 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, 2008, ASB’s costing liabilities consisted of 86% deposits and 14% other borrowings. As of December 31, 2007, ASB’s costing liabilities consisted of 71% deposits and 29% other borrowings. The decrease in the relative level of other borrowings and corresponding increase in the level of deposits was due to the early extinguishment of certain borrowings through the restructuring of ASB’s balance sheet. (See “Balance sheet restructure” in Note 4 of HEI’s Notes to Consolidated Financial Statements.) Competition for deposits and the level of 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.

Pressures from declines in the housing market will continue to impact securities held in ASB’s investment portfolio. Foreclosures within the subprime sector of the market have increased risk premiums for all mortgage-related securities, especially those underwritten in 2006 and 2007 for which underwriting standards for the collateral of the mortgage-related securities were thought to be most troublesome. While ASB does not have material exposure to securities backed by subprime collateral and does not hold any subprime positions issued within the last five years, a deep recession led by a material decline in housing prices could materially impair the value of the securities it currently holds. As of September 30, 2008, 52% of ASB’s portfolio is held in debentures or mortgage-related securities issued by government-sponsored entities. The remaining 48% of the portfolio is composed of mortgage-related securities issued by private issuers (43% are rated AAA and 5% are rated AA, A, or BBB by nationally recognized statistical rating organizations). While the credit quality of the portfolio remains sound, a significant downturn in housing prices combined with a prolonged recession could erode credit support of non-agency mortgage-related securities and result in realized and unrealized losses in ASB’s portfolio, and these losses could be material. The mortgage-related securities portfolio currently holds two positions whose principal is guaranteed by bond insurance companies whose ratings have been downgraded. The two positions, with a current book value of $0.3 million, are not impaired and ASB has the ability and intent to hold these positions to maturity.

On October 27 and 28, 2008, one rating agency downgraded two mortgage-related securities, with a current face value of approximately $36 million, from AAA to BB and B. These securities maintained investment grade ratings from other rating agencies. ASB will continue to analyze and monitor these securities.

Although higher long-term interest rates or other conditions in credit markets (such as the effects of the deteriorated subprime market) 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 (such as those that occurred in the balance sheet restructure) or an “other-than-temporary” impairment in the value of the securities. As of September 30, 2008 and December 31, 2007, 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 $10 million and $18 million, respectively. See “Quantitative and qualitative disclosures about market risk.”

Average Balance Sheet and Net Interest Margin

The following tables set forth average balances, together with interest and dividend income earned and accrued, and resulting yields and costs for the three and nine months ended September 30, 2008 and 2007.


	Three months ended September 30
	2008						2007
($ in thousands)	Average Balance			Interest		Average Rate (%)	Average Balance			Interest		Average Rate (%)
Assets:
Other investments¹	$	108,818		$	392	1.44	$	182,647		$	1,249	2.68
Investment and mortgage-related securities		868,530			9,506	4.38		2,324,404			25,248	4.34
Loans receivable²		4,156,656			61,100	5.87		3,960,694			61,817	6.23

Total interest-earning assets		5,134,004			70,998	5.52		6,467,745			88,314	5.45
Allowance for loan losses		(30,334	)					(31,262	)
Non-interest-earning assets		423,057						371,786

Total assets	$	5,526,727					$	6,808,269

Liabilities and Stockholder’s Equity:
Interest-bearing demand and savings deposits	$	2,093,666			2,735	0.52	$	2,131,387			4,119	0.77
Time certificates		1,425,334			11,335	3.16		1,620,152			16,262	3.98

Total interest-bearing deposits		3,519,000			14,070	1.59		3,751,539			20,381	2.16
Other borrowings		647,718			4,616	2.80		1,752,454			20,243	4.57

Total interest-bearing liabilities		4,166,718			18,686	1.77		5,503,993			40,624	2.92
Non-interest bearing liabilities:
Deposits		701,062						645,098
Other		103,235						96,748
Stockholder’s equity		555,712						562,430

Total Liabilities and Stockholder’s Equity	$	5,526,727					$	6,808,269

Net interest income				$	52,312					$	47,690

Net interest margin (%)³						4.08						2.97


	Nine months ended September 30
	2008						2007
($ in thousands)	Average Balance			Interest		Average Rate (%)	Average Balance			Interest		Average Rate (%)
Assets:
Other investments¹	$	130,905		$	1,538	1.56	$	198,179		$	4,303	2.87
Investment and mortgage-related securities		1,647,451			55,540	4.50		2,395,483			80,787	4.50
Loans receivable²		4,163,427			186,312	5.97		3,876,101			182,191	6.27

Total interest-earning assets		5,941,783			243,390	5.46		6,469,763			267,281	5.51
Allowance for loan losses		(30,134	)					(30,832	)
Non-interest-earning assets		419,025						371,759

Total assets	$	6,330,674					$	6,810,690

Liabilities and Stockholder’s Equity:
Interest-bearing demand and savings deposits	$	2,100,710			9,052	0.57	$	2,192,524			12,819	0.78
Time certificates		1,499,492			38,857	3.45		1,642,802			49,132	4.00

Total interest-bearing deposits		3,600,202			47,909	1.77		3,835,326			61,951	2.16
Other borrowings		1,363,097			40,030	3.91		1,678,190			57,230	4.54

Total interest-bearing liabilities		4,963,299			87,939	2.36		5,513,516			119,181	2.88
Non-interest bearing liabilities:
Deposits		681,198						639,586
Other		105,473						95,482
Stockholder’s equity		580,704						562,106

Total Liabilities and Stockholder’s Equity	$	6,330,674					$	6,810,690

Net interest income				$	155,451					$	148,100

Net interest margin (%)³						3.49						3.05

¹	Includes federal funds sold, interest bearing deposits and stock in the FHLB of Seattle ($98 million as of September 30, 2008).

²	Includes loan fees of $1.0 million for the three months ended September 30, 2008 and 2007 and $3.4 million for nine months ended September 30, 2008 and 2007, together with interest accrued prior to suspension of interest accrual on nonaccrual loans.

³	Defined as net interest income as a percentage of average earning assets.

Results – three months ended September 30, 2008

Net interest income before provision for loan losses for the third quarter of 2008 increased by $4.6 million, or 10%, when compared to the same period in 2007. Net interest margin increased from 2.97% in the third quarter of 2007 to 4.08% in the third quarter of 2008 as lower balances of investment and mortgage-related securities and lower yields on loans were more than offset by lower funding costs and higher balances on loans. The increase in the average loan portfolio balance was due, in part, to growth in the residential loan portfolio in 2007 as a result of the strength in the Hawaii economy and real estate market. The decrease in the average investment and mortgage-related securities portfolios was due to the sale of mortgage-related securities and agency notes in the second quarter balance sheet restructuring and the use of a portion of the proceeds from repayments in the portfolio to fund loans. (See “Balance sheet restructure” in Note 4 of HEI’s Notes to Consolidated Financial Statements.) Average deposit balances for the third quarter of 2008 decreased by $177 million compared to the third quarter of 2007, and decreased by $74 million compared to the second quarter of 2008. ASB experienced outflows in 2007 and 2008 as competitive factors and the level of short-term interest rates made it difficult to retain deposits. The shift in deposit mix from higher cost certificates to lower cost savings and checking accounts, along with the repricing of deposits as a result of a downward movement in the general level of interest rates, has contributed to decreased funding costs.

During the third quarter of 2008, ASB recorded a provision for losses of $2.0 million primarily due to the growth in the commercial loan portfolio and the reclassification of certain commercial loans due to weakening in their credit quality. In Hawaii, the residential real estate market is slowing and foreclosures rising. ASB’s delinquent loans have increased in 2008. As of September 30, 2008, ASB’s past due loans to total loans was 0.65%, compared to 0.29% and 0.19% as of December 31, 2007 and September 30, 2007, respectively.

Third quarter of 2008 noninterest income decreased by $0.5 million, or 3%, when compared to the third quarter of 2007.

Noninterest expense for the third quarter of 2008 decreased by $1.3 million, or 3%, when compared to the third quarter of 2007, primarily due to lower legal and consulting expenses, partly offset by higher compensation expenses.

Results – nine months ended September 30, 2008

Net interest income before provision for loan losses for the nine months ended September 30, 2008 increased by $7.4 million, or 5%, when compared to the same period in 2007. Net interest margin increased from 3.05% in the first nine months of 2007 to 3.49% in the first nine months of 2008 as lower yields on earning assets and lower balances of investment and mortgage-related securities were more than offset by lower funding costs and higher balances on loans. The increase in the average loan portfolio balance was due, in part, to growth in the residential loan portfolio in 2007 as a result of the strength in the Hawaii economy and real estate market. The decrease in the average investment and mortgage-related securities portfolios was due to the sale of mortgage-related securities and agency notes in the second quarter balance sheet restructuring and the use of a portion of the proceeds from repayments in the portfolio to fund loans. Average deposit balances decreased by $194 million compared to the first nine months of 2007. ASB experienced outflows in 2007 and 2008 as competitive factors and the level of short-term interest rates made it difficult to retain deposits. The outflow of higher cost certificates, along with the repricing of deposits as a result of a downward movement in the general level of interest rates, has contributed to decreased funding costs.

During the first nine months of 2008, ASB recorded a provision for losses of $4.0 million due to loan growth as well as the reclassification of certain commercial loans due to weakening in their credit quality. During the first nine months of 2007, ASB recorded a provision for losses of $3.9 million primarily for a single commercial borrower.


	Nine months ended September 30						Year ended December 31, 2007
	2008			2007			Year ended December 31, 2007
	(in thousands)
Allowance for loan losses, January 1	$	30,211		$	31,228		$	31,228
Provision for loan losses		4,034			3,900			5,700
Less: net charge-offs		2,645			1,406			6,717

Allowance for loan losses, end of period	$	31,600		$	33,722		$	30,211

Ratio of allowance for loan losses, end of period, to period end loans outstanding		0.75	%		0.83	%		0.73	%

Ratio of net charge-offs during the period to average loans outstanding (annualized)		0.08	%		0.05	%		0.17	%

Nonaccrual loans		10,036			8,385			3,195

Nonperforming assets to total assets		0.19	%		0.12	%		0.05	%

For the nine months ended September 30, 2008, noninterest income decreased by $14.1 million, or 28%, when compared to the same period of 2007, primarily due to losses on the sale of securities from the balance sheet restructuring. Excluding the losses from the balance sheet restructuring, noninterest income increased by $5.2 million primarily due to insurance recoveries on legal and litigation matters and gain on sales of stock in membership organizations.

Noninterest expense for the first nine months of 2008 increased by $32.8 million, or 24%, when compared to the first nine months of 2007, primarily due to losses on early extinguishment of certain borrowings from the balance sheet restructuring. Excluding the losses from the balance sheet restructuring, noninterest expenses decreased by $7.0 million primarily due to lower consulting and legal expenses, partly offset by higher compensation expenses.

FINANCIAL CONDITION

Liquidity and capital resources


(in millions)	September 30, 2008		December 31, 2007		% change
Total assets	$	5,515	$	6,861	(20	)
Available-for-sale investment and mortgage-related securities		766		2,141	(64	)
Investment in stock of FHLB of Seattle		98		98	—
Loans receivable, net		4,159		4,101	1
Deposit liabilities		4,183		4,347	(4	)
Other bank borrowings		683		1,811	(62	)

As of September 30, 2008, ASB was one of the largest financial institutions in Hawaii with assets of $5.5 billion. The decrease in assets since year-end was primarily due to the balance sheet restructuring.

In March 2007, Moody’s raised ASB’s counterparty credit rating to A3 from Baa3 and, in August 2008, maintained the rating following its annual review of ASB. In April 2007, S&P raised ASB’s long-term/short-term counterparty credit ratings to BBB/A-2 from BBB-/A-3 and in May 2008 maintained the rating following its annual review of ASB. These ratings reflect only the view, at the time the ratings are issued, of the applicable rating agency, from whom an explanation of the significance of such ratings may be obtained. Such 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, 2008, ASB’s unused FHLB borrowing capacity was approximately $1.4 billion. As of September 30, 2008, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.3 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 2008, net cash provided by ASB’s operating activities was $29 million. Net cash provided during the same period by ASB’s investing activities was $1.3 billion, primarily due to proceeds from the

sale of investment and mortgage-related securities of $1.3 billion and repayments of investment and mortgage-related securities of $0.5 billion, partly offset by purchases of investment and mortgage-related securities of $0.4 billion and a net increase in loans receivable of $0.1 billion. Net cash used in financing activities during this period was $1.4 billion, primarily due to net decreases in Federal Home Loan Bank advances, securities sold under agreements to repurchase and deposit liabilities of $0.6 billion, $0.5 billion, and $0.2 billion, respectively, and common stock dividends paid of $0.1 billion.

As of September 30, 2008, ASB was well-capitalized (minimum ratio requirements noted in parentheses) with a leverage ratio of 8.4% (5.0%), a Tier-1 risk-based capital ratio of 12.2% (6.0%) and a total risk-based capital ratio of 13.1% (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 50 to 52, HEI’s Quantitative and qualitative disclosures about market risk, which is incorporated into Part II, Item 7A of HEI’s 2007 Form 10-K by reference to HEI Exhibit 13 to HEI’s Current Report on Form 8-K dated February 21, 2008.

ASB’s interest-rate risk sensitivity measures as of September 30, 2008 and December 31, 2007 constitute “forward-looking statements” and were as follows:


	September 30, 2008						December 31, 2007
	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	(0.8	)%	8.10	%	(454	)	(2.2	)%	6.97	%	(334	)
+200	(0.5	)	9.65		(299	)	(0.9	)	8.27		(204	)
+100	(0.2	)	11.22		(142	)	(0.2	)	9.46		(85	)
Base	—		12.64		—		—		10.31		—
-100	(0.6	)	13.49		85		(0.5	)	10.40		9
-200	**		**		**		(3.0	)	9.67		(64	)
-300	**		**		**		(6.9	)	8.68		(163	)

*	Change from base case in basis points (bp).

**	For September 30, 2008, the -200 and -300 bp scenarios were not performed due to the low level of interest rate.

ASB’s net interest income (NII) sensitivity as of September 30, 2008 was less liability sensitive in the event of rising rates compared to December 31, 2007. In the -100 basis point scenario, NII sensitivity was slightly more asset sensitive than December 31, 2007 as the low level of interest rates limited the amount deposit rates could decline.

The increase in ASB’s base net portfolio value (NPV) ratio as of September 30, 2008 compared to December 31, 2007 was primarily due to the significant reduction in the size of ASB’s balance sheet, which resulted from the June 2008 balance sheet restructuring. The restructured balance sheet resulted in higher capital ratios and a higher base NPV ratio. As part of the restructuring, selected above market wholesale borrowings were terminated, which also contributed to the increase in the NPV ratio.

ASB’s NPV ratio sensitivity measure as of September 30, 2008 is more sensitive in the event of rising rates when compared to December 31, 2007 primarily due to the modeling of slower prepayment expectations.

The computation of the prospective effects of hypothetical interest rate changes on the NII sensitivity, NPV ratio, and NPV ratio sensitivity analyses is based on numerous assumptions, including relative levels of market interest rates, loan prepayments, balance changes and pricing strategies, and should not be relied upon as indicative of actual results (see page 51 of HEI Exhibit 13 to HEI’s Current Report on Form 8-K dated February 21, 2008 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:

Changes in Internal Control over Financial Reporting

During the third quarter of 2008, there was 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, 2008 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Constance H. Lau, HEI Chief Executive Officer, and Curtis Y. Harada, HEI Chief Financial Officer, have evaluated the disclosure controls and procedures of HEI as of September 30, 2008. Based on their evaluations, as of September 30, 2008, 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.

HECO:

Changes in Internal Control over Financial Reporting

During the third quarter of 2008, there was 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, 2008 that has materially affected, or is reasonably likely to materially affect, HECO and its subsidiaries’ internal control over financial reporting.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Constance H. Lau, HECO Principal Executive Officer, and Tayne S. Y. Sekimura, HECO Chief Financial Officer, have evaluated the disclosure controls and procedures of HECO as of September 30, 2008. Based on their evaluations, as of September 30, 2008, 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.

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 I. Item 3. Legal Proceedings,” “Part III, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part III, Item 8. Financial Statements and Supplementary Data”) 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 30 to 39 of HEI’s 2007 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 2007 Form 10-K, as updated on pages iv and v herein.

The following risk factor has been updated:

The Company is subject to risks associated with the Hawaii economy, volatile U.S. capital markets and changes in the interest rate and credit market environment that have and/or could result in higher pension plan funding requirements, declines in electric utility kilowatthour sales, declines in ASB’s interest rate margins and investment values, higher delinquencies and charge-offs in ASB’s loan portfolio and restrictions on the ability of HEI or its subsidiaries to borrow money or issue securities.

The two largest components of Hawaii’s economy are tourism and the federal government (including the military). Because the core businesses of HEI’s subsidiaries are providing local electric public utility services (through HECO and its subsidiaries) and banking services (through ASB and its subsidiaries) in Hawaii, the Company’s operating results are significantly influenced by Hawaii’s economy, which in turn is influenced by economic conditions in the mainland U.S. (particularly California) and Asia (particularly Japan) as a result of the impact of those conditions on tourism, by the impact of interest rates on the construction and real estate industries and by the impact of world conditions (e.g., war in Iraq) on federal government spending in Hawaii.

The current turmoil in the financial markets and declines in the national and global economies are having a negative effect on the Hawaii economy. Declines in the Hawaii economy, and the U.S. or Asian economies, have led to declines in KWH sales in the second and third quarters of 2008, and into the fourth quarter of 2008, and an increase in uncollected billings of HECO and its subsidiaries, higher delinquencies in ASB’s loan portfolio and other adverse effects on HEI’s businesses. Although lower fuel prices are starting to show up in customers’ bills, the utilities expect continued conservation by customers and full year 2008 kilowatthour (KWH) sales to decrease at a level similar to the year-to-date September 2008 sales decline of 1.2% (compared to the same period last year), primarily because of the ailing national and Hawaii economies’ impact on consumer decisions. A similar downward trend is expected in 2009. The expected decline in sales will adversely impact the utilities’ and consolidated HEI’s fourth quarter 2008 and 2009 results of operations. Given the current recessionary economic conditions and the associated uncertainty of U.S. and global financial markets, the Company’s and consolidated HECO’s financial metrics may erode. If these conditions continue for an extended period, the Company’s and consolidated HECO’s earnings may decline and ratings may be threatened. If S&P or Moody’s were to downgrade HEI’s or HECO’s long-term debt ratings because of these adverse effects, or if future events were to adversely affect the availability of capital to the Company, HEI’s and HECO’s ability to borrow and raise capital could be constrained and their future borrowing costs would likely increase with resulting reductions in HEI’s consolidated net income in

future periods. Further, if HEI’s or HECO’s commercial paper ratings were to be downgraded, HEI and HECO might not be able to sell commercial paper and might be required to draw on more expensive bank lines of credit or to defer capital or other expenditures.

Changes in the U.S. capital markets can also have significant effects on the Company. For example, pension funding requirements are affected by the market performance of the assets in the master pension trust maintained for pension plans, and by the discount rate used to determine the service and interest cost components of net periodic pension cost. The electric utilities’ pension tracking mechanisms help moderate pension expense, however, the recent significant decline in the value of defined benefit pension plan assets, in addition to continuing challenging market conditions in the fourth quarter of 2008, has resulted in sizable increases in expected funding requirements.

Because the earnings of ASB depend primarily on net interest income, interest rate risk is a significant risk of ASB’s operations. HEI and its electric utility subsidiaries are also exposed to interest rate risk primarily due to their periodic borrowing requirements, the discount rate used to determine pension funding requirements and the possible effect of interest rates on the electric utilities’ rates of return. Interest rates are sensitive to many factors, including general economic conditions and the policies of government and regulatory authorities. HEI cannot predict future changes in interest rates, nor be certain that interest rate risk management strategies it or its subsidiaries have implemented will be successful in managing interest rate risk.

Interest rate risk also represents a market risk factor affecting the fair value of ASB’s investment securities. Increases and decreases in prevailing interest rates generally translate into decreases and increases in fair values of those instruments. In addition, changes in credit spreads also impact the fair values of those instruments. In 2008, the credit markets have experienced significant disruptions, liquidity on many financial instruments has declined and residential mortgage delinquencies and defaults have increased. These disruptions have negatively impacted the fair value of ASB’s investment portfolio thus far in 2008, including during the fourth quarter of 2008, and continued volatility in the financial markets could further impact the fair value of this portfolio, which will have an adverse impact on ASB’s and HEI’s financial condition. For example, in October 2008, one rating agency downgraded two mortgage-related securities, with a current face value of approximately $36 million, from AAA to BB and B. While the credit quality of the investment portfolio remains sound, a severe and prolonged recession could erode the credit quality of ASB’s investments and may result in further negative changes in ratings and realized and unrealized losses in ASB’s portfolio. These losses could be material.

The following risk factor is added to the “Electric Utility Risks”:

The electric utilities may be subject to increased operational challenges and its results of operations, financial condition and liquidity may be adversely impacted in meeting the commitments and objectives of the HCEI Energy Agreement.

On October 20, 2008, the Governor of the State of Hawaii, the State of Hawaii Department of Business, Economic Development and Tourism, the Division of Consumer Advocacy of the State of Hawaii Department of Commerce and Consumer Affairs and the electric utilities (collectively, the parties), signed an Energy Agreement setting forth the goals and objectives of a Hawaii Clean Energy Initiative (HCEI) and the related commitments of the parties. The Energy Agreement provides that the parties pursue a wide range of actions with the purpose of decreasing the State of Hawaii’s dependence on imported fossil fuels through substantial increases in the use of renewable energy and implementation of new programs intended to secure greater energy efficiency and conservation. For a detailed discussion of certain of the electric utilities’ commitments contained in the Energy Agreement, see “Hawaii Clean Energy Initiative (HCEI)” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.”

The far-reaching nature of the Energy Agreement including the extent of renewable energy commitments and the proposal to implement a new regulatory model which would decouple revenues from sales, present new increased risks to the Company. Among such risks are: (1) the dependence on third party suppliers of renewable purchased energy, which if the utilities are unsuccessful in negotiating purchased power agreements with such IPPs or if a major IPP fails to deliver the anticipated capacity in its purchased power agreement, could impact the

utilities’ achievement of its commitments under the Energy Agreement and/or the utilities’ ability to deliver reliable service; (2) delays in acquiring or unavailability of non-fossil fuel supplies for renewable generation; (3) the impact of intermittent power to the electrical grid and reliability of service if appropriate supporting infrastructure is not installed or does not operate effectively; (4) the likelihood that the utilities may need to make substantial investments in related infrastructure, which could result in increased borrowings and, therefore, materially impact the financial condition and liquidity of the utilities; and (5) the commitment to support a variety of initiatives, which, if approved by the PUC, may have a material impact on the results of operations and financial condition of the utilities depending on their design and implementation. These programs include, but are not limited to, decoupling revenues from sales; implementing feed-in tariffs to encourage development of renewable energy; removing the system-wide caps on net energy metering (but limiting distributed generation interconnections on a per-circuit basis to no more than 15% of peak circuit demand); and developing an Energy Efficiency Portfolio Standard. Management cannot predict the ultimate impact or outcome of the implementation of these or other HCEI programs on the results of operations, financial condition and liquidity of the electric utilities.

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

(a) For the nine months ended September 30, 2008, HEI issued an aggregate of 31,600 shares of unregistered common stock pursuant to the HEI 1990 Nonemployee Director Stock Plan, as amended and restated effective May 6, 2008 (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
	2008	2007	2007	2006	2005	2004	2003
HEI and Subsidiaries
Excluding interest on ASB deposits	2.11	1.53	1.78	2.08	2.31	2.32	2.11
Including interest on ASB deposits	1.76	1.35	1.52	1.73	1.98	2.00	1.84
HECO and Subsidiaries	3.83	1.84	2.43	3.14	3.23	3.49	3.36

See HEI Exhibit 12.1 and HECO Exhibit 12.2.

B. News release.

On November 4, 2008, HEI issued a news release, “Hawaiian Electric Industries, Inc. Reports Solid Third Quarter 2008 Results.” See HEI Exhibit 99.1.

C. Assignment of participation interest in Credit Agreement.

In September 2008, HEI and HECO each consented to an Assignment and Acceptance Agreement dated as of September 18, 2008 by and between Lehman Brothers Bank, FSB (Assignor) and Bank Hapoalim BM (Assignee) under which Assignor transferred to Assignee its interests as a participant under the respective Credit Agreements with HEI and HECO, each dated as of March 31, 2006. The Assignment and Acceptance Agreements and consents are included in Item 6 as HEI Exhibit 10.1 and HECO Exhibit 10.9.

D. Letter agreement between T. Michael May and HECO and addendum.

On August 1, 2008, T. Michael May, 61, stepped down from his position as HECO President and Chief Executive Officer (CEO), and will retire from HECO on December 31, 2008. Under the terms of a letter agreement entered into on June 13, 2008, and as further amended by an Addendum to the HEI Supplemental Executive Retirement Plan executed on October 28, 2008, HECO has agreed that Mr. May will be eligible for payouts under HEI’s Executive Incentive Compensation Plan (EICP) and Long Term Incentive Plan in accordance with the terms of those plans and awards previously made under the plans. Further, if the incentive award for 2008 performance under the EICP is less than the amount Mr. May would receive if his 2008 goals were achieved at his “target” levels, then HECO has agreed to make up that shortfall with an additional cash payment to Mr. May in the amount of such shortfall and also to recognize, for purposes of payment calculations under the SERP, an amount equivalent to the amount by which his payments under the HEI Supplemental Executive Retirement Plan are less than they would have been had there not been that shortfall. The letter agreement and Addendum are included in Item 6 as HECO Exhibits 10.10 and 10.11.

E. Amended Plans.

The HEI Excess Pay Plan, HEI Supplemental Executive Retirement Plan, ASB Supplemental Executive Retirement, Disability, and Death Benefit Plan, HEI Executives’ Deferred Compensation Plan, HEI Non-Employee Directors’ Deferred Compensation Plan, and American Savings Bank Select Deferred Compensation Plan, non-tax-qualified plans sponsored by HEI and ASB, were amended and restated effective January 1, 2009, to comply with final regulations under Section 409A of the Internal Revenue Code. Accordingly, the rules that determine the time and form of benefits payable from the plans were amended to eliminate linkage to benefit elections under HEI’s and ASB’s tax-qualified retirement plans and to preclude the possible acceleration of deferred compensation payments, except as permitted under Section 409A. A lump sum benefit payable under certain circumstances from the HEI Supplemental Executive Retirement Plan was eliminated, and benefits paid from all plans to “specified employees,” as defined in Section 409A, on account of separation from service must be delayed until at least six months after the specified employee’s separation from service. The Executive Death Benefit Plan of HEI and Participating Subsidiaries was also amended effective January 1, 2009, primarily to revise administrative provisions to coordinate with the reorganization of HEI’s benefit plan administration.

The amended plans are included in Item 6 as HEI Exhibits 10.2 to 10.8.

F. HECO Audit Committee Charter

The HECO Audit Committee operates and acts under a written charter, which was adopted and approved by the HECO Board and may be found on HEI’s website at www.hei.com and is available in print to any HECO preferred shareholder who requests it.

Item 6. Exhibits


HEI Exhibit 3(ii)		Amended and Restated Bylaws of HEI as last amended October 31, 2008

HEI Exhibit 10.1		Assignment and Acceptance Agreement dated as of September 18, 2008 by and between Lehman Brothers Bank, FSB and Bank Hapoalim BM and HEI Consent

HEI Exhibit 10.2		HEI Executives’ Deferred Compensation Plan

HEI Exhibit 10.3		HEI Supplemental Executive Retirement Plan amended and restated as of January 1, 2009

HEI Exhibit 10.4		HEI Excess Pay Plan effective as of January 1, 2009



HEI Exhibit 10.5		HEI Non-Employee Directors’ Deferred Compensation Plan

HEI Exhibit 10.6		Executive Death Benefit Plan of HEI and Participating Subsidiaries effective as of January 1, 2009

HEI Exhibit 10.7		American Savings Bank Select Deferred Compensation Plan (Restatement Effective January 1, 2009)

HEI Exhibit 10.8		American Savings Bank Supplemental Executive Retirement, Disability, and Death Benefit Plan, effective January 1, 2009

HEI Exhibit 12.1		Hawaiian Electric Industries, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, nine months ended September 30, 2008 and 2007 and years ended December 31, 2007, 2006, 2005, 2004 and 2003

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 Curtis Y. Harada (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 Curtis Y. Harada (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 4, 2008, “Hawaiian Electric Industries, Inc. Reports Solid Third Quarter 2008 Results”

HECO Exhibit 10.9		Assignment and Acceptance Agreement dated as of September 18, 2008 by and between Lehman Brothers Bank, FSB and Bank Hapoalim BM and HECO Consent

HECO Exhibit 10.10		Letter agreement dated June 13, 2008 between T. Michael May and HECO

HECO Exhibit 10.11		HEI Supplemental Executive Retirement Plan Addendum for T. Michael May dated October 28, 2008

HECO Exhibit 10.12		Energy Agreement among the State of Hawaii, Division of Consumer Advocacy of the Department of Commerce and Consumer Affairs, and the Hawaiian Electric Companies

HECO Exhibit 12.2		Hawaiian Electric Company, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, nine months ended September 30, 2008 and 2007 and years ended December 31, 2007, 2006, 2005, 2004 and 2003

HECO Exhibit 31.3		Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Constance H. Lau (HECO Principal 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 Constance H. Lau (HECO Principal 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/ Constance H. Lau
	Constance H. Lau		Constance H. Lau
	President and Chief Executive Officer		Chairman of the Board
	(Principal Executive Officer of HEI)		(Principal Executive Officer of HECO)

By	/s/ Curtis Y. Harada	By	/s/ Tayne S. Y. Sekimura
	Curtis Y. Harada		Tayne S. Y. Sekimura
	Controller and Acting Financial Vice President, Treasurer and Chief Financial Officer		Senior Vice President, Finance and Administration (Principal Financial Officer of HECO)
	(Principal Accounting and Financial Officer of HEI)

		By	/s/ Patsy H. Nanbu
			Patsy H. Nanbu
			Controller
			(Principal Accounting Officer of HECO)

Date: November 4, 2008		Date: November 4, 2008