Edgar Filing: HAWAIIAN ELECTRIC CO 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 March 31, 2009

¨	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. has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No x

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No x

Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc. is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

APPLICABLE ONLY TO CORPORATE ISSUERS:

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


Class of Common Stock		Outstanding April 30, 2009

Hawaiian Electric Industries, Inc. (Without Par Value)		91,533,957 Shares
Hawaiian Electric Company, Inc. ($6-2/3 Par Value)		12,805,843 Shares (not publicly traded)

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.

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.

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended March 31, 2009

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 months ended March 31, 2009 and 2008
2		Consolidated Balance Sheets (unaudited) - March 31, 2009 and December 31, 2008
3		Consolidated Statements of Changes in Stockholders’ Equity (unaudited) - three months ended March 31, 2009 and 2008
4		Consolidated Statements of Cash Flows (unaudited) - three months ended March 31, 2009 and 2008
5		Notes to Consolidated Financial Statements (unaudited)

		Hawaiian Electric Company, Inc. and Subsidiaries
16		Consolidated Statements of Income (unaudited) - three months ended March 31, 2009 and 2008
17		Consolidated Balance Sheets (unaudited) - March 31, 2009 and December 31, 2008
18		Consolidated Statements of Changes in Common Stock Equity (unaudited) - three months ended March 31, 2009 and 2008
19		Consolidated Statements of Cash Flows (unaudited) - three months ended March 31, 2009 and 2008
20		Notes to Consolidated Financial Statements (unaudited)
42	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
42		HEI Consolidated
49		Electric Utilities
76		Bank
81	Item 3.	Quantitative and Qualitative Disclosures About Market Risk
82	Item 4.	Controls and Procedures

	PART II. OTHER INFORMATION
83	Item 1.	Legal Proceedings
83	Item 1A.	Risk Factors
83	Item 5.	Other Information
84	Item 6.	Exhibits
85	Signatures

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended March 31, 2009

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
CIP CT-1		Campbell Industrial Park combustion turbine No. 1
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, HECO Capital Trust III (unconsolidated subsidiary), Renewable Hawaii, Inc. and Uluwehiokama Biofuels Corp. 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.
HEIRSP		Hawaiian Electric Industries Retirement Savings Plan
HELCO		Hawaii Electric Light Company, Inc., an electric utility subsidiary of Hawaiian Electric Company, Inc.
HPOWER		City and County of Honolulu with respect to a power purchase agreement for a refuse-fired plant
HREA		Hawaii Renewable Energy Alliance
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:

•

international, national and local economic conditions, including the state of the Hawaii tourism 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 current capital and credit market conditions and federal and state responses to those conditions, such as the Emergency Economic Stabilization Act of 2008 (plan for a $700 billion bailout of the financial industry) and the American Economic Recovery and Reinvestment Act of 2009 (economic stimulus package);

•

weather and natural disasters, such as hurricanes, earthquakes, tsunamis, lightning strikes and the potential effects of global warming;

•

global developments, including 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 swine and avian flu pandemics;

•

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 common stock (HEI) under volatile and challenging market conditions;

•

a potentially reduced market for HEI’s and HECO’s commercial paper as a result of the Investment Company Institute’s March 2009 resolution that urges money market funds governed by SEC Rule 2a-7 under the Investment Company Act of 1940, to eliminate investments in “second tier securities,” such as commercial paper rated A-2 or P-2, by September 18, 2009;

•

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 laws, regulations, market conditions and other factors that result in changes in assumptions used to calculate retirement benefits costs and funding requirements and the fair value of ASB used to test goodwill for impairment;

•

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

•

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, county 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 (GHG) 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 and investment in infrastructure 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;

•

changes in accounting principles applicable to HEI, HECO, ASB and their subsidiaries, including the adoption of International Financial Reporting 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 IPPs;

•

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; 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)


Three months ended March 31	2009			2008
(in thousands, except per share amounts and ratio of earnings to fixed charges)
Revenues
Electric utility	$	461,797		$	623,889
Bank		82,032			105,844
Other		(32	)		(116	)

		543,797			729,617

Expenses
Electric utility		430,728			572,906
Bank		64,911			82,481
Other		3,500			3,484

		499,139			658,871

Operating income (loss)
Electric utility		31,069			50,983
Bank		17,121			23,363
Other		(3,532	)		(3,600	)

		44,658			70,746

Interest expense–other than on deposit liabilities and other bank borrowings		(17,833	)		(19,249	)
Allowance for borrowed funds used during construction		1,622			762
Allowance for equity funds used during construction		3,605			1,901

Income before income taxes		32,052			54,160
Income taxes		11,184			19,720

Net income		20,868			34,440
Less net income attributable to noncontrolling interest - preferred stock of subsidiaries		473			473

Net income for common stock	$	20,395		$	33,967

Basic earnings per common share	$	0.23		$	0.41

Diluted earnings per common share	$	0.22		$	0.41

Dividend per common share	$	0.31		$	0.31

Weighted-average number of common shares outstanding		90,604			83,472
Dilutive effect of stock-based compensation		88			142

Adjusted weighted-average shares		90,692			83,614


Ratio of earnings to fixed charges (SEC method)
Excluding interest on ASB deposits		2.31			2.31

Including interest on ASB deposits		1.87			1.90

For the three months ended March 31, 2009, under the two-class method of computing basic and diluted earnings per share, distributed earnings were $0.31 per share and undistributed losses were $0.09 per share for both unvested restricted stock awards and unrestricted common stock. For the three months ended March 31, 2008, under the two-class method of computing basic and diluted earnings per share, distributed earnings were $0.31 per share and undistributed earnings were $0.10 per share for both unvested restricted stock awards and unrestricted common stock.

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

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)


(dollars in thousands)	March 31, 2009			December 31, 2008
Assets
Cash and equivalents	$	160,222		$	182,903
Federal funds sold		1,137			532
Accounts receivable and unbilled revenues, net		198,923			300,666
Available-for-sale investment and mortgage-related securities		600,269			657,717
Investment in stock of Federal Home Loan Bank of Seattle (estimated fair value $97,764)		97,764			97,764
Loans receivable, net		4,014,961			4,206,492
Property, plant and equipment, net of accumulated depreciation of $1,879,389 and $1,851,813		2,959,900			2,907,376
Regulatory assets		531,078			530,619
Other		313,512			328,823
Goodwill, net		82,190			82,190

	$	8,959,956		$	9,295,082

Liabilities and stockholders’ equity
Liabilities
Accounts payable	$	158,711		$	183,584
Deposit liabilities		4,154,124			4,180,175
Other bank borrowings		436,071			680,973
Long-term debt, net—other than bank		1,214,681			1,211,501
Deferred income taxes		146,751			143,308
Regulatory liabilities		294,814			288,602
Contributions in aid of construction		312,933			311,716
Other		803,475			871,476

		7,521,560			7,871,335


Stockholders’ equity
Common stock, no par value, authorized 200,000,000 shares; issued and outstanding: 91,439,984 shares and 90,515,573 shares		1,245,048			1,231,629
Retained earnings		203,122			210,840
Accumulated other comprehensive loss, net of tax benefits		(44,067	)		(53,015	)

Common stock equity		1,404,103			1,389,454
Preferred stock, no par value, authorized 10,000,000 shares; issued: none		—			—
Noncontrolling interest: cumulative preferred stock of subsidiaries - not subject to mandatory redemption		34,293			34,293

		1,438,396			1,423,747

	$	8,959,956		$	9,295,082

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

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Changes in Stockholders’ Equity (unaudited)


	Common stock			Retained earnings			Accumulated other comprehensive loss			Noncontrolling interest: cumulative preferred stock of subsidiaries			Total
(in thousands, except per share amounts)	Shares	Amount		Retained earnings			Accumulated other comprehensive loss						Total
Balance, December 31, 2008	90,516	$	1,231,629	$	210,840		$	(53,015	)	$	34,293		$	1,423,747
Comprehensive income:
Net income	—		—		20,395			—			473			20,868
Net unrealized gains on securities
Net unrealized gains on securities arising during the period, net of taxes of $5,711	—		—		—			8,649			—			8,649
Retirement benefit plans:
Amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes of $1,862	—		—		—			2,918			—			2,918
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits of $1,668	—		—		—			(2,619	)		—			(2,619	)

Comprehensive income	—		—		20,395			8,948			473			29,816

Issuance of common stock, net	924		13,419		—			—			—			13,419
Common stock dividends ($0.31 per share)	—		—		(28,113	)		—			—			(28,113	)
Preferred stock dividends	—		—		—			—			(473	)		(473	)

Balance, March 31, 2009	91,440	$	1,245,048	$	203,122		$	(44,067	)	$	34,293		$	1,438,396


Balance, December 31, 2007	83,432	$	1,072,101	$	225,168		$	(21,842	)	$	34,293		$	1,309,720
Comprehensive income:
Net income	—		—		33,967			—			473			34,440
Net unrealized gains on securities
Net unrealized gains on securities arising during the period, net of taxes of $5,808	—		—		—			8,796			—			8,796
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $372	—		—		—			(563	)		—			(563	)
Retirement benefit plans:
Amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes of $923	—		—		—			1,448			—			1,448
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits of $834	—		—		—			(1,309	)		—			(1,309	)

Comprehensive income	—		—		33,967			8,372			473			42,812

Issuance of common stock, net	524		12,166		—			—			—			12,166
Common stock dividends ($0.31 per share)	—		—		(25,922	)		—			—			(25,922	)
Preferred stock dividends	—		—		—			—			(473	)		(473	)

Balance, March 31, 2008	83,956	$	1,084,267	$	233,213		$	(13,470	)	$	34,293		$	1,338,303

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

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)


Three months ended March 31	2009			2008
(in thousands)
Cash flows from operating activities
Net income for common stock	$	20,395		$	33,967
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment		38,494			37,882
Other amortization		594			2,860
Provision for loan losses		8,300			900
Loans receivable originated and purchased, held for sale		(171,390	)		(66,664	)
Proceeds from sale of loans receivable, held for sale		192,367			67,223
Deferred income taxes		(2,530	)		(5,874	)
Excess tax benefits from share-based payment arrangements		(21	)		(28	)
Allowance for equity funds used during construction		(3,605	)		(1,901	)
Changes in assets and liabilities
Decrease (increase) in accounts receivable and unbilled revenues, net		101,743			(3,857	)
Decrease (increase) in fuel oil stock		15,028			(9,269	)
Increase (decrease) in accounts payable		(24,873	)		11,667
Changes in prepaid and accrued income taxes and utility revenue taxes		(48,253	)		(41,888	)
Changes in other assets and liabilities		(11,045	)		950

Net cash provided by operating activities		115,204			25,968

Cash flows from investing activities
Available-for-sale investment and mortgage-related securities purchased		(109,364	)		(66,145	)
Principal repayments on available-for-sale investment and mortgage-related securities		180,918			132,885
Proceeds from sale of available-for-sale investment securities		–			935
Net decrease (increase) in loans held for investment		163,721			(52,401	)
Capital expenditures		(80,510	)		(48,882	)
Contributions in aid of construction		2,362			3,836
Other		86			(57	)

Net cash provided by (used in) investing activities		157,213			(29,829	)

Cash flows from financing activities
Net decrease in deposit liabilities		(26,051	)		(16,904	)
Net increase in short-term borrowings with original maturities of three months or less		–			107,501
Net increase (decrease) in retail repurchase agreements		(2,366	)		14,432
Proceeds from other bank borrowings		310,000			152,500
Repayments of other bank borrowings		(552,517	)		(188,600	)
Proceeds from issuance of long-term debt		3,148			9,897
Repayment of long-term debt		–			(50,000	)
Excess tax benefits from share-based payment arrangements		21			28
Net proceeds from issuance of common stock		7,365			6,314
Common stock dividends		(22,765	)		(20,676	)
Decrease in cash overdraft		(5,865	)		(8,582	)
Other		(5,463	)		(4,761	)

Net cash provided by (used in) financing activities		(294,493	)		1,149

Net decrease in cash and equivalents and federal funds sold		(22,076	)		(2,712	)
Cash and equivalents and federal funds sold, beginning of period		183,435			209,855

Cash and equivalents and federal funds sold, end of period	$	161,359		$	207,143

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 incorporated by reference in HEI’s Form 10-K for the year ended December 31, 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 March 31, 2009 and December 31, 2008 and the results of its operations and cash flows for the three months ended March 31, 2009 and 2008. 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 March 31, 2009
Revenues from external customers	$	461,761	$	82,032	$	4		$	543,797
Intersegment revenues (eliminations)		36		—		(36	)		—

Revenues		461,797		82,032		(32	)		543,797

Profit (loss)*		23,083		17,092		(8,123	)		32,052
Income taxes (benefit)		8,452		6,210		(3,478	)		11,184

Net income (loss)		14,631		10,882		(4,645	)		20,868
Less net income attributable to noncontrolling interest – preferred stock of HECO and its subsidiaries		499		—		(26	)		473

Net income (loss) for common stock		14,132		10,882		(4,619	)		20,395

Assets (at March 31, 2009)		3,793,747		5,159,756		6,453			8,959,956

Three months ended March 31, 2008
Revenues from external customers	$	623,849	$	105,844	$	(76	)	$	729,617
Intersegment revenues (eliminations)		40		—		(40	)		—

Revenues		623,889		105,844		(116	)		729,617

Profit (loss)*		40,305		23,341		(9,486	)		54,160
Income taxes (benefit)		15,221		8,765		(4,266	)		19,720

Net income (loss)		25,084		14,576		(5,220	)		34,440
Less net income attributable to noncontrolling interest – preferred stock of HECO and its subsidiaries		499		—		(26	)		473

Net income (loss) for common stock		24,585		14,576		(5,194	)		33,967

Assets (at March 31, 2008)		3,468,599		6,844,494		9,487			10,322,580

*	Income (loss) before income taxes.

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

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

3 • Electric utility subsidiary

For HECO’s consolidated financial information, including its commitments and contingencies, see pages 16 through 41.

4 • Bank subsidiary

Selected financial information

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

Consolidated Statements of Income Data (unaudited)


Three months ended March 31	2009		2008
(in thousands)
Interest and dividend income
Interest and fees on loans	$	58,092	$	63,465
Interest and dividends on investment and mortgage-related securities		7,676		24,451

		65,768		87,916

Interest expense
Interest on deposit liabilities		11,565		18,220
Interest on other borrowings		3,264		19,149

		14,829		37,369

Net interest income		50,939		50,547
Provision for loan losses		8,300		900

Net interest income after provision for loan losses		42,639		49,647

Noninterest income
Fees from other financial services		5,919		6,823
Fee income on deposit liabilities		6,711		6,794
Fee income on other financial products		1,044		1,804
Gain on sale of securities		–		935
Other income		2,590		1,572

		16,264		17,928

Noninterest expense
Compensation and employee benefits		19,360		18,240
Occupancy		5,129		5,397
Equipment		2,790		3,114
Services		3,418		5,673
Data processing		3,187		2,616
Other expense		7,927		9,194

		41,811		44,234

Income before income taxes		17,092		23,341
Income taxes		6,210		8,765

Net income for common stock	$	10,882	$	14,576

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

Consolidated Balance Sheets Data (unaudited)


(in thousands)	March 31, 2009			December 31, 2008
Assets
Cash and equivalents	$	151,080		$	168,766
Federal funds sold		1,137			532
Available-for-sale investment and mortgage-related securities		600,269			657,717
Investment in stock of Federal Home Loan Bank of Seattle		97,764			97,764
Loans receivable, net		4,014,961			4,206,492
Other		212,355			223,659
Goodwill, net		82,190			82,190

	$	5,159,756		$	5,437,120


Liabilities and stockholder’s equity
Deposit liabilities–noninterest-bearing	$	721,153		$	701,090
Deposit liabilities–interest-bearing		3,432,971			3,479,085
Other borrowings		436,071			680,973
Other		83,022			98,598

		4,673,217			4,959,746


Common stock		328,567			328,162
Retained earnings		197,333			197,235
Accumulated other comprehensive loss, net of tax benefits		(39,361	)		(48,023	)

		486,539			477,374

	$	5,159,756		$	5,437,120

Other borrowings consisted of securities sold under agreements to repurchase and advances from the Federal Home Loan Bank (FHLB) of Seattle of $234 million and $202 million, respectively, as of March 31, 2009 and $241 million and $440 million, respectively, as of December 31, 2008.

As of March 31, 2009, 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 a 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 $35.6 million in the second quarter of 2008. 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 this balance sheet restructuring, ASB freed up capital and paid a dividend of approximately $55 million to HEI in 2008. HEI used the dividend to repay commercial paper and for other corporate purposes. The OTS has approved ASB’s payment of quarterly dividends through the quarter ended June 30, 2009 to the

extent that payment of the dividend would not cause ASB’s Tier I leverage ratio to fall below 8% as of the end of the quarter.

Private-issue mortgage-related securities. As of March 31, 2009, the net unrealized losses on ASB’s investment in private-issue mortgage-related securities was due to multiple factors primarily related to continued deterioration in the residential housing market and spread widening for all credit sensitive sectors of the market. Increasing foreclosures coupled with recessionary employment pressures and declining housing prices have depressed the values of all private-issue mortgage collateralized securities as risks for this sector have increased. Changes in credit rating for issues originated in 2006 and 2007 have dramatically depressed valuations in this sector of the portfolio. While risks within this sector have increased, ASB believes that, based on its internal assessment of positions held in the portfolio and its ability and intent to hold these securities until a recovery of fair value, which may be at maturity, it does not consider securities held in this sector to be other-than-temporarily impaired at March 31, 2009.

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 by ASB prospectively and only partially applied as of January 1, 2008. In accordance with FASB Staff Position (FSP) FAS 157-2, the Company has delayed the application of SFAS No. 157 to ASB’s goodwill until the first quarter of 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 based on exit prices that are taken from identical or similar market transactions, even in situations where trading volume may be low when compared with prior periods as has been the case during the current market disruption. Inputs to these valuation techniques reflect the assumptions that consider credit and nonperformance risk that 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:


	March 31, 2009		Fair value measurements using
(in millions)	March 31, 2009		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
Available-for-sale securities	$	600	$	—	$	600	$	—

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 assumption. 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:


	March 31, 2009		Fair value measurements using
(in millions)	March 31, 2009		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
Loans	$	23.3	$	—	$	3.5	$	19.8

Specific reserves as of March 31, 2009 were $9.2 million and were included in loans receivable held for investment, net. For the three months ended March 31, 2009, there were no adjustments to fair value for ASB’s loans held for sale.

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 part 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 the fourth quarter of 2008, Visa reached a settlement in a case brought by Discover Financial Services. This case is “covered litigation” under Visa’s Retrospective Responsibility Plan and ASB’s proportionate share of this settlement is estimated to be $0.2 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.

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 financial institution 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 made changes to the assessment system to ensure that riskier institutions will bear a greater share of the proposed increase in assessments. Under the final rules, financial institutions in Risk Category I, the lowest risk group, will have an initial base assessment rate within the range of 12 to 16 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 7 to 24 basis points. The new assessment rates became effective April 1, 2009. The FDIC also raised 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 its current assessment rate is 12.2 basis points of deposits, or $1.5 million for the quarter ended March 31, 2009. ASB anticipates its assessment rate to be 14 to 15 basis points for the quarter beginning April 1, 2009.

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 other 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.

5 • Retirement benefits

Defined benefit plans. For the first quarter of 2009, HECO contributed $9.4 million and HEI contributed $0.4 million to their respective retirement benefit plans, compared to $0.9 million and $0.2 million, respectively, in the first quarter of 2008. The Company’s current estimate of contributions to its retirement benefit plans in 2009 is $27 million ($25 million to be made by the utilities, nil by ASB and $2 million by HEI), compared to contributions of $15 million in 2008 ($14 million made by the utilities, nil by ASB and $1 million by HEI). In addition, the Company expects to pay directly $2 million of benefits in 2009, compared to the $1 million paid in 2008.

For the first quarter of 2009, the Company’s defined benefit retirement plans’ assets generated a loss, including investment management fees, of 6.3%. The market value of the defined benefit retirement plans’ assets as of March 31, 2009 was $676 million compared to $726 million at December 31, 2008, a decline of approximately $50 million.

The components of net periodic benefit cost were as follows:


	Pension benefits						Other benefits
Three months ended March 31	2009 (1)			2008 (1)			2009			2008
(in thousands)
Service cost	$	6,341		$	6,856		$	1,056		$	1,165
Interest cost		15,538			14,876			2,847			2,838
Expected return on plan assets		(14,276	)		(18,232	)		(2,215	)		(2,740	)
Amortization of unrecognized transition obligation		1			1			785			785
Amortization of prior service cost (gain)		(93	)		(90	)		3			3
Recognized actuarial loss		3,969			1,690			116			—

Net periodic benefit cost		11,480			5,101			2,592			2,051
Impact of PUC D&Os		(4,091	)		1,657			(325	)		193

Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	7,389		$	6,758		$	2,267		$	2,244

(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 $7 million in each of the first quarters of 2009 and 2008, 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 matching contributions of 100% on the first 4% of eligible pay contributed by participants to HEI’s retirement savings plan for its eligible employees. In addition, a new ASB 401(k) Plan was created to initially fund a discretionary employer profit sharing contribution for the 2008 plan year, with the intent to transfer over ASB employee accounts from the HEI retirement savings plan to the new ASB 401(k) Plan in the second quarter of 2009. The discretionary employer profit sharing contribution will be allocated pro-rata to accounts of all eligible participants based on a flat percent of eligible pay. This percentage will be determined annually after year-end, based on ASB’s performance and achievement of financial goals. For the first quarters of 2009 and 2008, ASB’s total expense for its employees participating in the HEI retirement savings plan was $0.8 million and $1.1 million, respectively, and contributions were $0.5 million.

6 • Share-based compensation

Under the 1987 Stock Option and Incentive Plan, as amended (SOIP), HEI may issue an aggregate of 7.7 million shares of common stock (4.5 million shares available for issuance under outstanding and future grants and awards as of March 31, 2009) to officers and key employees as incentive stock options, nonqualified stock options (NQSOs), restricted stock awards, restricted stock units, stock appreciation rights (SARs), stock performance awards or dividend equivalents. HEI has issued new shares for NQSOs, restricted stock awards (nonvested stock), restricted stock units, stock performance awards, 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 for retirement eligible participants. 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 awards are paid quarterly in cash.

Restricted stock units generally vest and will be issued as unrestricted stock four years after the date of the grant. Restricted stock units expense has been recognized in accordance with the fair-value based measurement method of accounting. Dividend equivalent rights on restricted stock units are accrued quarterly and are paid in cash at the end of the restriction period when the restricted stock units vest.

Performance awards granted under the 2009-2011 Long-term Incentive Plan (LTIP) provide for payment in cash or shares of HEI common stock based on the achievement of certain financial goals over a three-year performance period. The Company accrues compensation expense based on the price of the Company’s common stock and reassesses at each reporting date whether achievement of the performance condition is probable.

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 March 31	2009	2008
($ in millions)
Share-based compensation expense ¹	0.4	0.3
Income tax benefit	0.1	0.1

The Company has not capitalized any share-based compensation cost. The estimated forfeiture rate for SARs was 8.8%, the estimated forfeiture rate for restricted stock was 30.2% and the estimated forfeiture rate for restricted stock units was 5.9%.

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


March 31, 2009			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	0.1	$	17.61
2000		14.74	46,000	1.1		14.74
2001		17.96	65,000	2.1		17.96
2002		21.68	122,000	2.9		21.68
2003		20.49	141,500	3.5		20.49

	$	14.74 – 21.68	375,500	2.7	$	19.73

As of December 31, 2008, NQSOs outstanding totaled 375,500 (representing the same number of underlying shares), with a weighted-average exercise price of $19.73. As of March 31, 2009, all NQSO’s outstanding were exercisable and had no intrinsic value.

NQSO activity and statistics are summarized as follows:


Three months ended March 31	2009	2008
($ in thousands, except prices)
Shares granted	—		—
Shares forfeited	—		—
Shares expired	—		—
Shares vested	—		—
Aggregate fair value of vested shares	—		—
Shares exercised	—		12,000
Weighted-average exercise price	—	$	20.49
Cash received from exercise	—	$	246
Intrinsic value of shares exercised ¹	—	$	84
Tax benefit realized for the deduction of exercises	—	$	33
Dividend equivalent shares distributed under Section 409A	—		6,125
Weighted-average Section 409A distribution price	—	$	22.38
Intrinsic value of shares distributed under Section 409A	—	$	137
Tax benefit realized for Section 409A distributions	—	$	53

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.

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


March 31, 2009			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	2.1	$	26.02	295,000	2.1	$	26.02
2005		26.18	490,000	3.3		26.18	262,000	1.0		26.18

	$	26.02 – 26.18	785,000	2.9	$	26.12	557,000	1.6	$	26.10

As of December 31, 2008, the shares underlying SARs outstanding totaled 791,000, with a weighted-average exercise price of $26.12. As of March 31, 2009, the SARs outstanding and exercisable (including dividend equivalents) had no intrinsic value.

SARs activity and statistics are summarized as follows:


Three months ended March 31	2009		2008
($ in thousands, except prices)
Shares granted		—		—
Shares forfeited		6,000		—
Shares expired		—		—
Shares vested		—		15,000
Aggregate fair value of vested shares		—	$	87
Shares exercised		—		—
Weighted-average exercise price		—		—
Cash received from exercise		—		—
Intrinsic value of shares exercised ¹		—		—
Tax benefit realized for the deduction of exercises		—		—
Dividend equivalent shares distributed under Section 409A		3,143		—
Weighted-average Section 409A distribution price	$	13.64		—
Intrinsic value of shares distributed under Section 409A	$	43		—
Tax benefit realized for Section 409A distributions	$	17		—

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 March 31, 2009, there was $17,000 of total unrecognized compensation cost related to SARs and that cost is expected to be recognized over a weighted average period of 1 month.

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 three months ended March 31, 2009 and 2008 a total of 3,143 and 6,125 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. The dividend equivalents associated with the 2005 SAR grants are planned to be paid in March 2010. These are the last dividend equivalents intended to be paid in accordance with this Section 409A modified distribution.

Restricted stock awards. As of March 31, 2009 and December 31, 2008, restricted stock award shares outstanding totaled 138,500 and 160,500, with a weighted-average grant date fair value of $25.48 and $25.51, respectively. The grant date fair value of a grant of a restricted stock award share was the closing or average price of HEI common stock on the date of grant.

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


Three months ended March 31	2009		2008
($ in thousands)
Shares vested		594		—
Shares forfeited		21,406		6,000
Grant date fair value	$	551	$	157
Shares granted		—		—
Grant date fair value		—		—

The tax benefit realized for the tax deductions related to restricted stock awards was immaterial for the first quarters of 2009 and 2008.

As of March 31, 2009, there was $1.7 million of total unrecognized compensation cost related to nonvested restricted stock awards. The cost is expected to be recognized over a weighted-average period of 2.4 years.

Restricted stock units. In February 2009, 70,500 restricted stock units (representing the same number of underlying shares) were granted to officers and key employees with a grant date fair value of $1.2 million and a

weighted-average grant date fair value of $16.99 per restricted stock unit. The grant date fair value of the restricted stock units was the average price of HEI common stock on the date of grant. As of March 31, 2009, there were 70,500 restricted stock units outstanding, none were vested and none were forfeited.

As of March 31, 2009, there was $1.1 million of total unrecognized compensation cost related to the nonvested restricted stock units. The cost is expected to be recognized over a weighted-average period of 3.9 years.

Performance Shares. Under the 2009-2011 LTIP, performance awards, which provide for payment in shares of HEI common stock or cash based on achievement of certain financial goals and service conditions over a three-year performance period were granted on February 20, 2009 to certain key executives. The payout varies from 0% to 280% of the number of shares depending on achievement of the goals. Performance conditions require the achievement of stated goals for total return to shareholders as a percentile to the Edison Electric Institute Index and return on average common equity targets. The Company accrues compensation expense over the performance period based on the price of the Company’s common stock and reassesses at each reporting date whether achievement of the performance condition is probable.

As of March 31, 2009, there were 60,329 shares underlying nonvested performance awards outstanding, based on target performance levels. The performance awards had a weighted average remaining contractual term of 2.75 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 three months ended March 31, 2009 and 2008, the Company paid interest (net of amounts capitalized and including bank interest) to non-affiliates amounting to $25 million and $50 million, respectively.

For the three months ended March 31, 2009 and 2008, the Company paid income taxes amounting to $0.7 million and $38 million, respectively. The significant decrease in taxes paid was due primarily to the difference in the taxes due with the extensions for tax years 2008 and 2007. In 2007, 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. Taxable income for 2008 was much larger in the first half versus the second half of the year, resulting in only a nominal amount due in the first quarter of 2009.

Supplemental disclosures of noncash activities. Noncash increases in common stock for director and officer compensatory plans of the Company were $0.5 million and $0.6 million for the three months ended March 31, 2009 and 2008, 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 $5 million for each of the first quarters of 2009 and 2008. Effective April 16, 2009, HEI began satisfying 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 issuing additional shares.

9 • Recent accounting pronouncements and interpretations

See “SFAS No. 157, Fair Value Measurements” in Note 4.

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 to 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 adopted SFAS No. 160 prospectively on January 1, 2009, except for the presentation and disclosure requirements which must be applied retrospectively. Thus, beginning in the first quarter of 2009, “Preferred stock of subsidiaries—not subject to mandatory redemption” is 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 is 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” has been added to the statement of changes in stockholders’ equity.

Participating securities. In June 2008, the FASB issued FASB Staff Position (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 adopted FSP EITF 03-6-1 in the first quarter of 2009 retrospectively and determined that restricted stock award grants were participating securities. The impact of adoption of FSP EITF 03-6-1 on the Company’s financial statements was not material.

Fair value measurements and impairments. In April 2009, the FASB issued three Staff Positions (FSPs) providing additional application guidance and enhancing disclosures regarding fair value measurements and impairments of securities.

FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” (FSP 157-4) relates to determining fair values when there is no active market or where the price inputs being used represent distressed sales. FSP 157-4 provides guidelines for making fair value measurements more consistent with the principles presented in FASB Statement No. 157, Fair Value Measurements, by reaffirming that the objective of fair value measurement is to reflect how much an asset would be sold for in an orderly transaction (as opposed to a distressed or forced transaction) at the date of the financial statements under current market conditions. Specifically, FSP 157-4 reaffirms the need to use judgment in determining fair values when markets have become inactive.

FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” (FSP 107-1) relates to fair value disclosures for any financial instruments that are not currently reflected on the balance sheet of companies at fair value. Prior to issuance of FSP 107-1, fair values for these assets and liabilities were only disclosed annually. FSP 107-1 now requires these disclosures on a quarterly basis, providing qualitative and quantitative information about fair value estimates for financial instruments not measured on the balance sheet at fair value.

FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments,” provides greater consistency to the timing of impairment recognition and greater clarity to investors about the credit and noncredit components of impaired debt securities that are not expected to be sold. The measure of impairment in comprehensive income remains fair value. FSP FAS 115-2 and FAS 124-2 also require increased and more timely disclosures regarding expected cash flows, credit losses and an aging of securities with unrealized losses.

The Company will adopt the FSPs in the second quarter of 2009 and will be required to provide additional disclosures regarding fair value measurements and other-than-temporary impairments. In the fourth quarter of 2008 the Company determined the impairment on two private-issue mortgage-related securities to be other- than-temporary, adjusted the carrying values to market value, and recognized a noncash impairment charge of $4.7 million, net of income tax, in the fourth quarter of 2008. Upon adoption of the FSPs, the Company expects a significant portion of the previously recognized impairment to be reclassified to accumulated other comprehensive income.

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)


Three months ended March 31	2009			2008
(in thousands, except ratio of earnings to fixed charges)
Operating revenues	$	459,285		$	622,494

Operating expenses
Fuel oil		145,289			249,543
Purchased power		114,484			150,795
Other operation		62,397			55,579
Maintenance		26,163			23,613
Depreciation		36,424			35,434
Taxes, other than income taxes		45,735			57,486
Income taxes		8,544			15,378

		439,036			587,828

Operating income		20,249			34,666

Other income
Allowance for equity funds used during construction		3,605			1,901
Other, net		2,368			1,096

		5,973			2,997

Income before interest and other charges		26,222			37,663

Interest and other charges
Interest on long-term debt		11,912			11,724
Amortization of net bond premium and expense		675			631
Other interest charges		626			986
Allowance for borrowed funds used during construction		(1,622	)		(762	)

		11,591			12,579

Income before preferred stock dividends of HECO and subsidiaries		14,631			25,084
Less net income attributable to noncontrolling interest - preferred stock of subsidiaries		229			229

Income before preferred stock dividends of HECO		14,402			24,855
Preferred stock dividends of HECO		270			270

Net income for common stock	$	14,132		$	24,585

Ratio of earnings to fixed charges (SEC method)		2.49			3.77

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)	March 31, 2009			December 31, 2008
Assets
Utility plant, at cost
Land	$	42,541		$	42,541
Plant and equipment		4,305,782			4,277,499
Less accumulated depreciation		(1,767,821	)		(1,741,453	)
Construction in progress		319,362			266,628

Net utility plant		2,899,864			2,845,215

Current assets
Cash and equivalents		4,227			6,901
Customer accounts receivable, net		93,699			166,422
Accrued unbilled revenues, net		79,170			106,544
Other accounts receivable, net		7,510			7,918
Fuel oil stock, at average cost		62,687			77,715
Materials and supplies, at average cost		35,809			34,532
Prepayments and other		10,796			12,626

Total current assets		293,898			412,658

Other long-term assets
Regulatory assets		531,078			530,619
Unamortized debt expense		14,194			14,503
Other		54,713			53,114

Total other long-term assets		599,985			598,236

	$	3,793,747		$	3,856,109

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		806,186			802,590
Accumulated other comprehensive income, net of income taxes		1,710			1,651

Common stock equity		1,192,497			1,188,842
Cumulative preferred stock – not subject to mandatory redemption		22,293			22,293
Noncontrolling interest – cumulative preferred stock of subsidiaries – not subject to mandatory redemption		12,000			12,000

Stockholders’ equity		1,226,790			1,223,135
Long-term debt, net		907,681			904,501

Total capitalization		2,134,471			2,127,636

Current liabilities
Short-term borrowings–affiliate		29,339			41,550
Accounts payable		107,146			122,994
Interest and preferred dividends payable		18,552			15,397
Taxes accrued		169,207			220,046
Other		53,874			55,268

Total current liabilities		378,118			455,255

Deferred credits and other liabilities
Deferred income taxes		164,788			166,310
Regulatory liabilities		294,814			288,602
Unamortized tax credits		61,059			58,796
Retirement benefits liability		392,351			392,845
Other		55,213			54,949

Total deferred credits and other liabilities		968,225			961,502

Contributions in aid of construction		312,933			311,716

	$	3,793,747		$	3,856,109

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Changes in Stockholders’ Equity (unaudited)


(in thousands, except per share amounts)	Common stock			Premium on capital income (loss)		Retained earnings			Accumulated other comprehensive income (loss)			Cumulative preferred stock			Noncontrolling interest: cumulative preferred stock of subsidiaries			Total
(in thousands, except per share amounts)	Shares	Amount		Premium on capital income (loss)		Retained earnings						Cumulative preferred stock						Total
Balance, December 31, 2008	12,806	$	85,387	$	299,214	$	802,590		$	1,651		$	22,293		$	12,000		$	1,223,135
Comprehensive income:
Net income	—		—		—		14,132			—			270			229			14,631
Retirement benefit plans:
Amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes of $1,706	—		—		—		—			2,678			—			—			2,678
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits of $1,668	—		—		—		—			(2,619	)		—			—			(2,619	)

Comprehensive income	—		—		—		14,132			59			270			229			14,690

Common stock dividends	—		—		—		(10,536	)		—			—			—			(10,536	)
Preferred stock dividends	—		—		—		—			—			(270	)		(229	)		(499	)

Balance, March 31, 2009	12,806	$	85,387	$	299,214	$	806,186		$	1,710		$	22,293		$	12,000		$	1,226,790


Balance, December 31, 2007	12,806	$	85,387	$	299,214	$	724,704		$	1,157		$	22,293		$	12,000		$	1,144,755
Comprehensive income:
Net income	—		—		—		24,585			—			270			229			25,084
Retirement benefit plans:
Amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes of $870	—		—		—		—			1,366			—			—			1,366
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits of $834	—		—		—		—			(1,309	)		—			—			(1,309	)

Comprehensive income	—		—		—		24,585			57			270			229			25,141

Common stock dividends	—		—		—		(14,089	)		—			—			—			(14,089	)
Preferred stock dividends	—		—		—		—			—			(270	)		(229	)		(499	)

Balance, March 31, 2008	12,806	$	85,387	$	299,214	$	735,200		$	1,214		$	22,293		$	12,000		$	1,155,308

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)


Three months ended March 31	2009			2008
(in thousands)
Cash flows from operating activities
Income before preferred stock dividends of HECO	$	14,402		$	24,855
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities
Depreciation of property, plant and equipment		36,424			35,434
Other amortization		2,206			2,163
Deferred income taxes		(1,290	)		(5,953	)
Tax credits, net		2,514			435
Allowance for equity funds used during construction		(3,605	)		(1,901	)
Changes in assets and liabilities
Decrease (increase) in accounts receivable		73,131			(7,902	)
Decrease in accrued unbilled revenues		27,374			3,818
Decrease (increase) fuel oil stock		15,028			(9,269	)
Increase in materials and supplies		(1,277	)		(981	)
Increase in regulatory assets		(4,255	)		(2,326	)
Increase (decrease) in accounts payable		(15,848	)		454
Changes in prepaid and accrued income and utility revenue taxes		(49,561	)		(41,106	)
Changes in other assets and liabilities		5,771			9,528

Net cash provided by operating activities		101,014			7,249

Cash flows from investing activities
Capital expenditures		(80,315	)		(47,729	)
Contributions in aid of construction		2,362			3,836
Other		—			(57	)

Net cash used in investing activities		(77,953	)		(43,950	)

Cash flows from financing activities
Common stock dividends		(10,536	)		(14,089	)
Preferred stock dividends		(270	)		(270	)
Proceeds from issuance of long-term debt		3,148			9,897
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		(12,211	)		60,317
Decrease in cash overdraft		(5,865	)		(8,582	)
Other		(1	)		—

Net cash provided by (used in) financing activities		(25,735	)		47,273

Net increase (decrease) in cash and equivalents		(2,674	)		10,572
Cash and equivalents, beginning of period		6,901			4,678

Cash and equivalents, end of period	$	4,227		$	15,250

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, 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 March 31, 2009 and December 31, 2008 and the results of their operations and cash flows for the three months ended March 31, 2009 and 2008. 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 currently redeemable at the issuer’s option without premium. 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 March 31, 2009 and December 31, 2008 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 three months ended March 31, 2009 and 2008 each consisted of $0.8 million of interest income received from the 2004 Debentures; $0.8 million of distributions to holders of the Trust Preferred Securities; and $25,000 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 March 31, 2009, 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 three months ended March 31, 2009 totaled $114 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $32 million, $34 million, $15 million and $10 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” (e.g., 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 each year from 2005 to 2009, 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 its 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 HELCO and MECO 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 cogeneration contract with another customer, the term of which coincides with the PPA. The facility has been certified by the Federal Energy Regulatory Commission as a Qualifying Facility under the Public Utility Regulatory Policies Act of 1978.

Pursuant to the provisions of FIN 46R, HECO is deemed to have a variable interest in Kalaeloa by reason of the provisions of HECO’s PPA with Kalaeloa. However, management has concluded that HECO is not the primary beneficiary of Kalaeloa because HECO does not absorb the majority of Kalealoa’s expected losses nor receive a majority of Kalaeloa’s expected residual returns and, thus, HECO has not consolidated Kalaeloa in its consolidated financial statements. A significant factor affecting the level of expected losses HECO would absorb is the fact that HECO’s exposure to fuel price variability is limited to the remaining term of the PPA as compared to the facility’s remaining useful life. Although HECO absorbs fuel price variability for the remaining term of the PPA, the PPA does not currently expose HECO to losses as the fuel and fuel related energy payments under the PPA have been approved by the PUC for recovery from customers through base electric rates and through HECO’s ECAC to the extent the fuel and fuel related energy payments are not included in base energy rates.

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 three months ended March 31, 2009 and 2008, HECO and its subsidiaries included approximately $43 million and $55 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 quarter of 2009, HECO and its subsidiaries contributed $9.4 million to their retirement benefit plans, compared to $0.9 million in the first quarter of 2008. HECO and its subsidiaries’ current estimate of contributions to their retirement benefit plans in 2009 is $25 million, compared to contributions of $14 million in 2008. In addition, HECO and its subsidiaries expect to pay directly $0.9 million of benefits in 2009, compared to $0.1 million paid in 2008.

For the first quarter of 2009, HECO and its subsidiaries’ defined benefit retirement plans’ assets generated a loss, including investment management fees, of 6.3%. The market value of the defined benefit retirement plan’s assets as of March 31, 2009 was $610 million compared to $655 million at December 31, 2008, a decline of approximately $45 million.

The components of net periodic benefit cost were as follows:


	Pension benefits						Other benefits
Three months ended March 31	2009			2008			2009			2008
(in thousands)
Service cost	$	6,060		$	6,533		$	1,027		$	1,135
Interest cost		14,050			13,445			2,765			2,755
Expected return on plan assets		(12,673	)		(16,251	)		(2,178	)		(2,695	)
Amortization of unrecognized transition obligation		—			—			783			782
Amortization of prior service gain		(183	)		(191	)		—			—
Recognized actuarial loss		3,671			1,645			114			—

Net periodic benefit cost		10,925			5,181			2,511			1,977
Impact of PUC D&Os		(4,091	)		1,657			(325	)		193

Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	6,834		$	6,838		$	2,186		$	2,170

HECO and its subsidiaries recorded retirement benefits expense of $7 million in each of the first quarters of 2009 and 2008. 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, any 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, except when limited by material, adverse consequences imposed by federal regulations.

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 a subsequent rate case proceeding. However, 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. In January 2008, the State of Hawaii and the U.S. Department of Energy (DOE) signed a memorandum of understanding establishing the Hawaii Clean Energy Initiative (HCEI). The stated purpose of the HCEI is to establish a long-term partnership between the State of Hawaii and the DOE that will result in a fundamental and sustained transformation in the way in which energy resources are planned and used in the State. HECO has been working with the State, 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 goals and objectives under the HCEI and the related commitments of the parties (the Energy Agreement). The Energy Agreement provides that the parties pursue a wide range of actions with the purpose of decreasing the State of Hawaii’s dependence on imported fossil fuels through substantial increases in the use of renewable energy and implementation of new programs intended to secure greater energy efficiency and conservation.

The parties recognize that the move toward a more renewable and distributed and intermittent power 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 in 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 Energy 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 Energy Agreement most directly affecting HECO and its subsidiaries are the following:

The Energy 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 Energy 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 Energy 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.

In December 2007, the PUC issued a D&O approving a stipulated RPS framework to govern electric utilities’ compliance with the RPS law. In a follow up order in December 2008, the PUC approved a penalty of $20 for every MWh that an electric utility is deficient under Hawaii’s RPS law. The PUC noted, however, that this penalty may be reduced, in the PUC’s discretion, due to events or circumstances that are outside an electric utility’s reasonable control, to the extent the event or circumstance could not be reasonably foreseen and ameliorated, as described in the RPS law and in the RPS Framework. In addition, the PUC ordered that: (1) any penalties assessed against HECO and its subsidiaries for failure to meet the RPS will go into the public benefits fund account used to support energy efficiency and DSM programs and services, unless otherwise directed; and (2) the utilities will be prohibited from recovering any RPS penalty costs through rates.

To further encourage the contributions of energy efficiency to the overall HCEI goal, the Energy 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 Energy Agreement provides that the parties will request that the PUC establish a Public Benefits Fund (PBF) that is funded by collecting 1% of the utilities’ revenues in years one and two after implementation of a PBF; 1.5% in years three and four; and 2% thereafter. In December 2008, the PUC issued an order directing the utilities to collect revenue equal to 1% of the projected total electric revenue of the utilities, of which 60% shall be collected via the DSM surcharge and 40% via the PBF surcharge. Beginning January 1, 2009, the 1% is being assessed on customers of HECO and its subsidiaries.

The Energy 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 Energy 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. On November 28, 2008, HECO and the Consumer Advocate filed a joint letter informing the PUC that the pending REIP Surcharge satisfies the Energy Agreement provision for an implementation procedure for the CEIS recovery mechanism and that no further regulatory action on the CEIS is necessary, and reaffirming that the REIP Surcharge is ready for PUC decision-making. In the first quarter of 2009, the parties responded to information requests prepared by the PUC’s consultant.

HECO and its subsidiaries will continue to negotiate with developers of currently proposed projects (identified in the Energy 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 have agreed 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 has agreed 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 Energy Agreement includes support of the parties for the development of a feed-in tariff (FIT) system with standardized purchase prices for renewable energy. The PUC was requested to conclude an investigative proceeding by March 2009 to determine the best design for an FIT that supports the HCEI goals, considering such factors as categories of renewables, size or locational limits for projects qualifying for the FIT, what annual limits should apply to the amount of renewables allowed to utilize the FIT, what factors to incorporate into the prices set for FIT payments, and other terms and conditions. Based on these understandings, the Energy Agreement required 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 FITs. The utilities and Consumer Advocate were named as initial parties to the proceeding and 18 other parties were granted intervener or participant status. On December 11, 2008, the PUC issued a scoping paper prepared by its consultant that specified certain issues and questions for the parties to address and for the utilities and the Consumer Advocate to consider in a joint FIT proposal. On December 23, 2008, the utilities and the Consumer Advocate filed a joint proposal on FITs that called for the establishment of simple, streamlined and broad standard payment rates, which can be offered to as many renewable technologies as feasible. It proposed that the initial FIT be focused on photovoltaics (PV), concentrated solar power (CSP), in-line hydropower and wind, with individual project sizes targeted to provide a greater likelihood of more straightforward interconnection, project implementation and use of standardized energy rates and power purchase contracting. The FIT would be regularly reviewed to update tariff pricing to applicable technologies, project sizes and annual targets. An FIT update would be conducted for all islands in the utilities’ service territory not later than two years after initial implementation of the FIT and every three years thereafter. The proposed initial target project sizes are:

•

PV systems up to and including 500 kilowatts (kW) on Oahu, PV systems up to and including 250 kW on Maui and the island of Hawaii and PV systems up to and including 100 kW on Lanai and Molokai.

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CSP systems up to and including 500 kW on Oahu, Maui, and the island of Hawaii and up to and including 100 kW on Lanai and Molokai.

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In-line hydropower systems up to and including 100 kW on Oahu, Maui, Lanai, Molokai and the island of Hawaii.

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Wind power systems up to and including 100 kW on Oahu, Maui, Lanai, Molokai and the island of Hawaii.

The FIT joint proposal also recommended that no applications for new net energy metering contracts be accepted once the FIT is formally made available to customers (although existing net energy metering systems under contract would be grandfathered), and no applications for new Schedule Q contracts would be accepted once an FIT is formally made available for the resource type. Schedule Q would continue as an option for qualifying projects of 100 kW and less for which an FIT is not available. Final position statements in the FIT docket were submitted by the parties at the end of March 2009, and panel hearings were held in April 2009. Remaining procedural steps include opening briefs at the end of May 2009, reply briefs in June 2009 and proposed tariffs on September 1, 2009.

The Energy 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 Energy 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 could be 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. 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.

On October 24, 2008, the PUC opened an investigative proceeding to examine implementing a decoupling mechanism for the utilities. In addition to the utilities and the Consumer Advocate, there are five other parties in the proceeding. The utilities and the Consumer Advocate filed a joint statement of position in March 2009, which was discussed in a technical workshop held in April 2009. The remaining schedule for the proceeding includes final position statements of the parties to be submitted in May 2009 and panel hearings during June 2009.

The PUC has been requested to approve the establishment of a revenue balancing account to be effective upon the issuance of the PUC’s interim D&O in HECO’s 2009 test year rate case. The Energy 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. On March 20, 2009, MECO filed a Notice of Intent to file an application for a general rate increase on or after May 29, 2009 (but before June 30, 2009) and a motion requesting PUC approval to use a 2009 calendar year test period for this upcoming rate case. On April 27, 2009, the PUC issued an order denying MECO’s motion and stating that MECO may elect to file its rate case application with either a split 2009/2010 test period or a 2010 calendar test period, pursuant to the PUC’s rules. Under the rules, MECO (and HELCO) would be allowed to file rate cases with 2010 test years on or after July 1, 2009.

The Energy Agreement confirms that the existing ECAC 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 utilities 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 Energy 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) improving and expanding “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 FITs in each utility’s respective rate base through January 2015; (g) delinking prices paid under all new renewable energy contracts from oil prices; and (h) exploring the possibility of establishing lifeline rates designed to provide a cap on rates for those who are unable to pay the full cost of electricity. The utilities’ proposed Lifeline Rate Program, submitted to the PUC for approval at the end of April 2009, would provide a monthly bill credit to qualified, low-income customers estimated to be in the range of $25 to $35 per month. The utilities and the Consumer Advocate are in discussions as to the appropriate recovery mechanism for the utilities to recover the cost of the credits passed on to program participants.

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 $24.6 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, a 4.96% increase 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 March 31, 2009, HECO and its subsidiaries had recognized $171 million of revenues with respect to interim orders ($5 million related to interim orders regarding certain integrated resource planning costs and $166 million related to interim orders regarding general rate increase requests). Revenue amounts recorded pursuant to interim orders are subject to refund, with interest, pending a final order.

Energy cost adjustment clauses. Hawaii Act 162 (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 expected 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.

In December 2008, HECO filed updates to its 2009 test year rate case. The updates proposed the establishment of a purchased power adjustment clause to recover non-energy purchased power costs, pursuant to the Energy Agreement provision stating the utilities “will be allowed to pass through reasonably incurred purchase power contract costs, including all capacity, operation and maintenance (O&M) and other non-energy payments” approved by the PUC through a separate surcharge. The purchased power adjustment clause will be adjusted monthly and reconciled quarterly.

On December 30, 2008, HECO and the Consumer Advocate filed joint proposed findings of fact and conclusions of law in the HECO 2007 test year rate case, which stated that, given the Energy Agreement, which documents a course of action to make Hawaii energy independent and recognizes the need to maintain HECO’s financial health while achieving that objective, as well as the overwhelming support in the record for maintaining the ECAC in its current form, the PUC should determine that HECO’s proposed ECAC complies with the requirements of Act 162.

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 March 31, 2009 noted in parentheses) include HECO’s Campbell Industrial Park (CIP) combustion turbine No. 1 (CIP CT-1) and a transmission line ($129 million), HECO’s East Oahu Transmission Project ($39 million), HELCO’s ST-7 ($69 million) and a customer information system ($22 million).

CIP CT-1 and transmission line. 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.

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 March 31, 2009, HECO’s cost estimate for the Project (exclusive of the costs of the community benefit measures described above) was $193 million (of which $129 million had been incurred, including $6 million of AFUDC) and outstanding commitments for materials, equipment and outside services totaled $28 million. To the extent actual project costs are higher than the estimate included in the 2009 test year rate case, HECO plans to seek recovery in a future proceeding. Management believes no adjustment to project costs is required as of March 31, 2009. 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 (Imperium), to supply biodiesel for the planned generating unit, subject to PUC approval. Imperium agreed to comply with HECO’s procurement policy requiring sustainable sources of 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. In January 2009, HECO and Imperium amended the contract, Imperium assigned the contract to Imperium Grays Harbor, LLC (Imperium GH), and HECO filed the amended contract with the PUC. In February 2009, HECO requested PUC approval of a related terminalling and trucking agreement with Aloha Petroleum, Ltd. to support the delivery and storage on Oahu of biodiesel from Imperium GH. In February 2009, the PUC modified the procedural schedule for this proceeding, and re-opened the evidentiary hearing, which re-commenced in March 2009. After the parties file proposed findings of fact and conclusions of law and then their respective comments on the same in May 2009, the application should be ready for PUC decision-making.

East Oahu Transmission Project (EOTP). HECO had planned a project (EOTP) to construct a partially 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 (then estimated at $56 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.

The project is currently estimated to cost $74 million and 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 March 31, 2009, the accumulated costs recorded for the EOTP amounted to $39 million, including (i) $12 million of planning and permitting costs incurred prior to 2003, (ii) $8 million of planning, permitting and construction costs incurred after 2002 and (iii) $19 million for AFUDC. Management believes no adjustment to project costs is required as of March 31, 2009. 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.

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. In January 1994, the PUC approved expenditures for CT-4. In 1995, the PUC allowed HELCO to pursue construction of and commit expenditures for CT-5 and ST-7, but noted that such costs are not to be included in rate base until the project is installed and “is used and useful for utility purposes.”

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 (the Settlement Agreement) 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 currently can be operated as required to meet HELCO’s system needs, but additional noise mitigation work is ongoing to ensure compliance with the applicable night-time noise standard.

HELCO has completed engineering and design activities and construction work for ST-7 is progressing towards completion in mid-2009. As of March 31, 2009, HELCO’s cost estimate for ST-7 was $92 million (of which $69 million had been incurred) and outstanding commitments for materials, equipment and outside services totaled $17 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.

Customer Information System (CIS) Project. On August 26, 2004, HECO, HELCO and MECO filed a joint application with the PUC for approval of the accounting treatment and recovery of certain costs related to acquiring and implementing a new CIS. The application stated that the new CIS would allow the utilities to (i) more quickly and accurately store, maintain and manage customer-specific information necessary to provide basic customer service functions, such as producing bills, collecting payments, establishing service and fulfilling customer requests in the field, and (ii) have substantially greater capabilities and features than the existing system, enabling the utilities to enhance their operations, including customer service. In a D&O filed on May 3, 2005, the PUC approved the utilities’ request to (i) expend the then-estimated amount of $20.4 million for the new CIS, provided that no part of the project costs may be included in rate base until the project is in service and is “used and useful for public utility purposes,” and (ii) defer certain computer software development costs, accumulate an allowance for funds used during construction during the deferral period, amortize the deferred costs over a specified period and include the unamortized deferred costs in rate base, subject to specified conditions.

Following a competitive bidding process, HECO signed a contract with Peace Software US Inc. (Peace) in March 2006 to have Peace develop, deliver and implement the new CIS, with a transition to the new CIS

originally scheduled to occur in 2008. The CIS project is currently in the development and implementation phase and has experienced delays, for which HECO considers Peace responsible. In July 2008, HECO notified the PUC that, due to cost overruns and other issues, the total estimated cost of the project had increased to $39.5 million and the transition to the new CIS would be postponed to 2009. In April 2009, HECO notified the PUC that, due to the delays and other issues, a transition to the new CIS was no longer expected to occur in 2009. Because a transition to the new CIS had previously been anticipated in 2009, HECO initially included in its 2009 test year rate case its share of certain costs related to the new CIS being placed into service during 2009. Since the transition to the new CIS is no longer expected to occur in 2009, HECO has subsequently agreed to remove most of those costs from 2009 test year rate case estimates. HECO is considering options under the Peace contract, and HECO has asserted that Peace is in breach of the contract. HECO is evaluating the recovery plan developed with Peace to complete installation of the new CIS using the Peace software, and its options to complete the needed CIS if its contract with Peace is terminated. A new anticipated transition date has not yet been determined. HECO plans to seek recovery in a future proceeding for the new CIS costs in accordance with the May 3, 2005 D&O. 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., wind plant developments on Molokai and Lanai producing in aggregate up to 400 MW of wind power would be owned by a third-party developer, and the undersea cable system to bring the power generated by the wind plants to Oahu is currently planned to be 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.

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 experience 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. HECO has been involved since 1995 in a work group with several other potentially responsible parties (PRPs) identified by the DOH, 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, to date all the investigative and remedial work has focused on the Iwilei Unit.

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. Once the DOH makes a remedial determination, the Participating Parties are required to develop remedial designs for the various elements of the remedy chosen. The DOH has completed remedial determinations for two subunits to date and the Participating Parties have initiated the remedial design work for those subunits. The Participating Parties anticipate that the DOH will complete the remaining remedial determinations during 2009 and anticipate that all remedial design work will be completed by the end of 2009 or early 2010. The Participating Parties will begin implementation of the remedial design elements as they are approved by the DOH.

Through March 31, 2009, HECO has accrued a total of $3.3 million for estimates of HECO’s share of costs for continuing investigative work, remedial activities and monitoring for the Iwilei unit. As of March 31, 2009, 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 – Steam Electric Generating Units. 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. 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 vacating the EPA’s Delisting Rule. Also, an industry group sought review of the Delisting Rule decision. On February 6, 2009, the EPA filed a motion with the Supreme Court to withdraw its petition for review. In the motion, the EPA indicated that it would begin rulemaking to establish MACT standards for EGUs. On February 23, 2009, the U.S. Supreme Court dismissed the petitions filed by the EPA and industry group requesting review of the decision vacating the EPA’s Delisting Rule.

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. Management is currently evaluating its options regarding potential MACT standards for applicable HECO steam units, but will need to review the standards adopted by the EPA before determining its ultimate response and course of action.

Hazardous Air Pollutant (HAP) Control – Reciprocating Internal Combustion Engines. On February 25, 2009, the EPA issued proposed MACT standards that would regulate HAPs from certain existing diesel compression ignition engines and gasoline spark ignition engines (i.e., reciprocating internal combustion engines or RICE). As proposed, the RICE MACT rule would require installation of pollution control devices on 80 RICE at the utilities’ facilities. Eight of the utilities’ RICE would be required to implement only specified maintenance practices, rather than install pollution control equipment. If adopted, the RICE MACT rule would provide a three-year compliance period after its effective date. Under the terms of a consent decree, the EPA is required to complete the final rule

by February 10, 2010. Management is evaluating the impacts of the proposed RICE MACT rule, including potential capital expenditures and other compliance costs.

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 establishing 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, including the EPA’s use of a cost-benefit analysis to determine compliance options. 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 Second Circuit Court of Appeal’s rejection of a cost-benefit test to determine compliance options. On April 1, 2009, the Supreme Court issued its opinion, ruling that it was permissible, but not required, for the EPA to rely on a cost-benefit analysis in developing cooling water intake standards under the Clean Water Act and to allow variances from the standards based on a cost-benefit comparison. The Supreme Court remanded the case. Because it remains unclear what form the regulations will take and whether the EPA will retain the cost-benefit portions of the rule, 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 March 31, 2009, approximately 57% 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 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 their results of operations and financial condition.

6 • Cash flows

Supplemental disclosures of cash flow information. For the three months ended March 31, 2009 and 2008, HECO and its subsidiaries paid interest amounting to $8 million and $9 million, respectively.

For the three months ended March 31, 2009, HECO and its subsidiaries received an income tax refund amounting to $2.0 million. For the three months ended March 31, 2008, HECO and its subsidiaries paid income taxes amounting to $33 million. The significant change was due primarily to the difference in the taxes refundable or due with the extensions for tax years 2008 and 2007. In 2007, 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. Taxable income for 2008 was larger in the first half versus the second half of the year, resulting in overpayments being refunded in the first quarter of 2009.

Supplemental disclosure of noncash activities. The allowance for equity funds used during construction, which was charged to construction in progress as part of the cost of electric utility plant, amounted to $3.6 million and $1.9 million for the three months ended March 31, 2009 and 2008, 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 March 31	2009			2008
(in thousands)
Operating income from regulated and nonregulated activities before income taxes (per HEI consolidated statements of income)	$	31,069		$	50,983
Deduct:
Income taxes on regulated activities		(8,544	)		(15,378	)
Revenues from nonregulated activities		(2,512	)		(1,395	)
Add:
Expenses from nonregulated activities		236			456

Operating income from regulated activities after income taxes (per HECO consolidated statements of income)	$	20,249		$	34,666

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.

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. See Note 2 above. 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 March 31, 2009


(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and eliminations		HECO consolidated
Operating revenues	$	305,461		84,631		69,193		—		—		—		$	459,285

Operating expenses
Fuel oil		98,931		15,764		30,594		—		—		—			145,289
Purchased power		75,845		33,407		5,232		—		—		—			114,484
Other operation		43,076		9,994		9,327		—		—		—			62,397
Maintenance		16,658		5,938		3,567		—		—		—			26,163
Depreciation		20,797		8,251		7,376		—		—		—			36,424
Taxes, other than income taxes		30,683		8,246		6,806		—		—		—			45,735
Income taxes		6,229		850		1,465		—		—		—			8,544

		292,219		82,450		64,367		—		—		—			439,036

Operating income		13,242		2,181		4,826		—		—		—			20,249

Other income
Allowance for equity funds used during construction		2,702		742		161		—		—		—			3,605
Equity in earnings of subsidiaries		3,960		—		—		—		—		(3,960	)		—
Other, net		1,878		569		81		(7	)	(7	)	(146	)		2,368

		8,540		1,311		242		(7	)	(7	)	(4,106	)		5,973

Income (loss) before interest and other charges		21,782		3,492		5,068		(7	)	(7	)	(4,106	)		26,222

Interest and other charges
Interest on long-term debt		7,668		1,976		2,268		—		—		—			11,912
Amortization of net bond premium and expense		403		151		121		—		—		—			675
Other interest charges		477		207		88		—		—		(146	)		626
Allowance for borrowed funds used during construction		(1,168	)	(388	)	(66	)	—		—		—			(1,622	)

		7,380		1,946		2,411		—		—		(146	)		11,591

Income (loss) before preferred stock dividends of HECO and subsidiaries		14,402		1,546		2,657		(7	)	(7	)	(3,960	)		14,631
Less net income attributable to noncontrolling interest – preferred stock of subsidiaries		—		134		95		—		—		—			229

Income (loss) before preferred stock dividends of HECO		14,402		1,412		2,562		(7	)	(7	)	(3,960	)		14,402
Preferred stock dividends of HECO		270		—		—		—		—		—			270

Net income (loss) for common stock	$	14,132		1,412		2,562		(7	)	(7	)	(3,960	)	$	14,132

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Three months ended March 31, 2008


(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and eliminations		HECO consolidated
Operating revenues	$	414,513		105,192		102,789		—		—		—		$	622,494

Operating expenses
Fuel oil		172,152		24,046		53,345		—		—		—			249,543
Purchased power		99,779		41,359		9,657		—		—		—			150,795
Other operation		37,969		8,894		8,716		—		—		—			55,579
Maintenance		15,276		4,705		3,632		—		—		—			23,613
Depreciation		20,552		7,834		7,048		—		—		—			35,434
Taxes, other than income taxes		38,448		9,619		9,419		—		—		—			57,486
Income taxes		9,494		2,587		3,297		—		—		—			15,378

		393,670		99,044		95,114		—		—		—			587,828

Operating income		20,843		6,148		7,675		—		—		—			34,666

Other income
Allowance for equity funds used during construction		1,502		255		144		—		—		—			1,901
Equity in earnings of subsidiaries		9,301		—		—		—		—		(9,301	)		—
Other, net		1,411		267		58		(23	)	(254	)	(363	)		1,096

		12,214		522		202		(23	)	(254	)	(9,664	)		2,997

Income (loss) before interest and other charges		33,057		6,670		7,877		(23	)	(254	)	(9,664	)		37,663

Interest and other charges
Interest on long-term debt		7,525		1,952		2,247		—		—		—			11,724
Amortization of net bond premium and expense		400		107		124		—		—		—			631
Other interest charges		862		405		82		—		—		(363	)		986
Allowance for borrowed funds used during construction		(585	)	(117	)	(60	)	—		—		—			(762	)

		8,202		2,347		2,393		—		—		(363	)		12,579

Income (loss) before preferred stock dividends of HECO and subsidiaries		24,855		4,323		5,484		(23	)	(254	)	(9,301	)		25,084
Less net income attributable to noncontrolling interest – preferred stock of subsidiaries		—		134		95		—		—		—			229

Income (loss) before preferred stock dividends of HECO		24,855		4,189		5,389		(23	)	(254	)	(9,301	)		24,855
Preferred stock dividends of HECO		270		—		—		—		—		—			270

Net income (loss) for common stock	$	24,585		4,189		5,389		(23	)	(254	)	(9,301	)	$	24,585

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

March 31, 2009


(in thousands)	HECO			HELCO		MECO		RHI	UBC	Reclassifications and Eliminations		HECO Consolidated
Assets
Utility plant, at cost
Land	$	33,213		4,982		4,346		—	—	—		$	42,541
Plant and equipment		2,583,884		878,477		843,421		—	—	—			4,305,782
Less accumulated depreciation		(1,040,897	)	(359,319	)	(367,605	)	—	—	—			(1,767,821	)
Construction in progress		227,693		82,021		9,648		—	—	—			319,362

Net utility plant		1,803,893		606,161		489,810		—	—	—			2,899,864

Investment in wholly owned subsidiaries, at equity		439,286		—		—		—	—	(439,286	)		—

Current assets
Cash and equivalents		477		2,628		1,005		105	12	—			4,227
Advances to affiliates		66,550		—		24,500		—	—	(91,050	)		—
Customer accounts receivable, net		58,997		20,753		13,949		—	—	—			93,699
Accrued unbilled revenues, net		53,699		14,406		11,065		—	—	—			79,170
Other accounts receivable, net		4,679		2,662		1,075		—	11	(917	)		7,510
Fuel oil stock, at average cost		42,070		9,314		11,303		—	—	—			62,687
Materials & supplies, at average cost		17,471		4,628		13,710		—	—	—			35,809
Prepayments and other		7,143		2,694		1,143		—	—	(184	)		10,796

Total current assets		251,086		57,085		77,750		105	23	(92,151	)		293,898

Other long-term assets
Regulatory assets		389,330		76,791		64,957		—	—	—			531,078
Unamortized debt expense		9,602		2,228		2,364		—	—	—			14,194
Other		39,254		7,962		7,378		—	119	—			54,713

Total other long-term assets		438,186		86,981		74,699		—	119	—			599,985

	$	2,932,451		750,227		642,259		105	142	(531,437	)	$	3,793,747

Capitalization and liabilities
Capitalization
Common stock equity	$	1,192,497		222,821		216,233		98	134	(439,286	)	$	1,192,497
Cumulative preferred stock – not subject to mandatory redemption		22,293		—		—		—	—	—			22,293
Noncontrolling interest – cumulative preferred stock of subsidiaries – not subject to mandatory redemption		—		7,000		5,000		—	—	—			12,000

Stockholders’ equity		1,214,790		229,821		221,233		98	134	(439,286	)		1,226,790
Long-term debt, net		582,150		151,185		174,346		—	—	—			907,681

Total capitalization		1,796,940		381,006		395,579		98	134	(439,286	)		2,134,471

Current liabilities
Short-term borrowings-affiliate		53,839		66,550		—		—	—	(91,050	)		29,339
Accounts payable		74,270		22,363		10,513		—	—	—			107,146
Interest and preferred dividends payable		11,625		3,198		3,778		—	—	(49	)		18,552
Taxes accrued		111,218		28,352		29,821		—	—	(184	)		169,207
Other		33,677		8,541		12,509		7	8	(868	)		53,874

Total current liabilities		284,629		129,004		56,621		7	8	(92,151	)		378,118

Deferred credits and other liabilities
Deferred income taxes		133,192		20,269		11,327		—	—	—			164,788
Regulatory liabilities		206,630		50,823		37,361		—	—	—			294,814
Unamortized tax credits		34,128		14,184		12,747		—	—	—			61,059
Retirement benefits liability		286,608		53,440		52,303		—	—	—			392,351
Other		11,770		35,868		7,575		—	—	—			55,213

Total deferred credits and other liabilities		672,328		174,584		121,313		—	—	—			968,225

Contributions in aid of construction		178,554		65,633		68,746		—	—	—			312,933

	$	2,932,451		750,227		642,259		105	142	(531,437	)	$	3,793,747

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

December 31, 2008


(in thousands)	HECO			HELCO		MECO		RHI	UBC	Reclassifications and Eliminations		HECO Consolidated
Assets
Utility plant, at cost
Land	$	33,213		4,982		4,346		—	—	—		$	42,541
Plant and equipment		2,567,018		874,322		836,159		—	—	—			4,277,499
Less accumulated depreciation		(1,028,501	)	(352,382	)	(360,570	)	—	—	—			(1,741,453	)
Construction in progress		188,754		68,650		9,224		—	—	—			266,628

Net utility plant		1,760,484		595,572		489,159		—	—	—			2,845,215

Investment in wholly owned subsidiaries, at equity		437,033		—		—		—	—	(437,033	)		—

Current assets
Cash and equivalents		2,264		3,148		1,349		123	17	—			6,901
Advances to affiliates		62,000		—		12,000		—	—	(74,000	)		—
Customer accounts receivable, net		109,724		32,108		24,590		—	—	—			166,422
Accrued unbilled revenues, net		74,657		17,876		14,011		—	—	—			106,544
Other accounts receivable, net		3,983		2,217		1,143		—	11	564			7,918
Fuel oil stock, at average cost		53,546		10,326		13,843		—	—	—			77,715
Materials & supplies, at average cost		16,583		4,366		13,583		—	—	—			34,532
Prepayments and other		6,918		2,311		3,664		—	—	(267	)		12,626

Total current assets		329,675		72,352		84,183		123	28	(73,703	)		412,658

Other long-term assets
Regulatory assets		388,054		77,038		65,527		—	—	—			530,619
Unamortized debt expense		9,802		2,282		2,419		—	—	—			14,503
Other		38,099		7,699		7,197		—	119	—			53,114

Total other long-term assets		435,955		87,019		75,143		—	119	—			598,236

	$	2,963,147		754,943		648,485		123	147	(510,736	)	$	3,856,109

Capitalization and liabilities
Capitalization
Common stock equity	$	1,188,842		221,405		215,382		105	141	(437,033	)	$	1,188,842
Cumulative preferred stock – not subject to mandatory redemption		22,293		—		—		—	—	—			22,293
Noncontrolling interest – cumulative preferred stock of subsidiaries – not subject to mandatory redemption		—		7,000		5,000		—	—	—			12,000

Stockholders’ equity		1,211,135		228,405		220,382		105	141	(437,033	)		1,223,135
Long-term debt, net		582,132		148,030		174,339		—	—	—			904,501

Total capitalization		1,793,267		376,435		394,721		105	141	(437,033	)		2,127,636

Current liabilities
Short-term borrowings-affiliate		53,550		62,000		—		—	—	(74,000	)		41,550
Accounts payable		84,238		27,795		10,961		—	—	—			122,994
Interest and preferred dividends payable		10,242		2,547		2,819		—	—	(211	)		15,397
Taxes accrued		144,366		38,117		37,830		—	—	(267	)		220,046
Other		33,462		9,015		11,992		18	6	775			55,268