Edgar Filing: HAWAIIAN ELECTRIC INDUSTRIES INC

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.

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 the HCEI and the related commitments of the parties (the agreement). The 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.

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