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 June 30, 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 ¨

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 ¨

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 July 31, 2009

Hawaiian Electric Industries, Inc. (Without Par Value)		91,557,514 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 June 30, 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 and six months ended June 30, 2009 and 2008
2		Consolidated Balance Sheets (unaudited) - June 30, 2009 and December 31, 2008
3		Consolidated Statements of Changes in Stockholders’ Equity (unaudited) - six months ended June 30, 2009 and 2008
4		Consolidated Statements of Cash Flows (unaudited) - six months ended June 30, 2009 and 2008
5		Notes to Consolidated Financial Statements (unaudited)

		Hawaiian Electric Company, Inc. and Subsidiaries
23		Consolidated Statements of Income (unaudited) - three and six months ended June 30, 2009 and 2008
24		Consolidated Balance Sheets (unaudited) - June 30, 2009 and December 31, 2008
25		Consolidated Statements of Changes in Common Stock Equity (unaudited) - six months ended June 30, 2009 and 2008
26		Consolidated Statements of Cash Flows (unaudited) - six months ended June 30, 2009 and 2008
27		Notes to Consolidated Financial Statements (unaudited)
53	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
53		HEI Consolidated
61		Electric Utilities
90		Bank
99	Item 3.	Quantitative and Qualitative Disclosures About Market Risk
101	Item 4.	Controls and Procedures

	PART II. OTHER INFORMATION
101	Item 1.	Legal Proceedings
102	Item 1A.	Risk Factors
102	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds
102	Item 4.	Submission of Matters to a Vote of Security Holders
103	Item 5.	Other Information
104	Item 6.	Exhibits
105	Signatures

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended June 30, 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 American Savings Holdings, 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).
ASHI		American Savings Holdings, Inc., formerly HEI Diversified, Inc., a wholly owned subsidiary of Hawaiian Electric Industries, Inc. and the parent company of American Savings Bank, F.S.B.
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); American Savings Holdings, 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

GLOSSARY OF TERMS, continued


Terms		Definitions
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).
HEI		Hawaiian Electric Industries, Inc., direct parent company of Hawaiian Electric Company, Inc., American Savings Holdings, 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.
HEIII		HEI Investments, Inc. (formerly HEI Investment Corp.) (in dissolution), 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
OTTI		Other-than-temporary impairment
PPA		Power purchase agreement
PRPs		Potentially responsible parties
PUC		Public Utilities Commission of the State of Hawaii
RBA		Revenue balancing account
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), which could result in higher loan loss provisions and write-offs and material other-than-temporary impairment (OTTI) charges), 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 H1N1 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 (including lines of credit) and to access capital markets to issue common stock (HEI) under volatile and challenging market conditions, and the cost of such financings, if available;

•

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), revenue decoupling and the fulfillment by the utilities of their commitments under the Energy Agreement (given the PUC approvals needed; the PUC’s delay in considering HCEI-related costs; reliance on outside parties like the state, independent power producers (IPPs) and developers; potential changes in political support; and uncertainties surrounding wind power, the undersea cable, biofuels, environmental assessments and the impacts of implementation of the HCEI on future costs of electricity);

•

capacity and supply constraints or difficulties, especially if generating units (utility-owned or 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 impact on customer satisfaction and political and regulatory support resulting from volatility in fuel prices;

•

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), governmental fees and assessments (such as Federal Deposit Insurance Corporation assessments), potential carbon “cap and trade” legislation that may fundamentally alter costs to produce electricity and accelerate the move to renewable generation, and the potential elimination of the Office of Thrift Supervision (OTS) and the grandfathering provisions of the Gramm-Leach-Bliley Act of 1998 that have permitted HEI to own ASB);

•

decisions by the Public Utilities Commission of the State of Hawaii (PUC) in rate cases (including the risks of delays in the timing of decisions, adverse changes in final decisions from interim decisions and the disallowance of project costs);

•

decisions in other proceedings and by other agencies and courts on land use, environmental and other permitting issues (such as required corrective actions, restrictions and penalties that may arise, for example with respect to environmental conditions or renewable portfolio standards (RPS)); enforcement actions by the OTS and other governmental authorities (such as 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;

•

the ability of ASB to execute its performance improvement initiatives, including the reduction of expenses through the conversion to the Fiserv Inc. bank platform system;

•

the risks associated with the geographic concentration of HEI’s businesses and ASB’s loans and investments, ASB’s concentration in a single product type (first mortgages), ASB’s significant credit relationships (i.e., concentrations of large loans and/or credit lines with certain customers) and Alt-A exposure in ASB’s mortgage-related securities portfolio;

•

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,” SFAS No. 167, “Amendments to FASB Interpretation No. 46(R),” 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 June 30						Six months ended June 30
	2009			2008			2009			2008
(in thousands, except per share amounts and ratio of earnings to fixed charges)
Revenues
Electric utility	$	450,417		$	688,121		$	912,214		$	1,312,010
Bank		75,499			85,950			157,531			191,794
Other		(15	)		(16	)		(47	)		(132	)

		525,901			774,055			1,069,698			1,503,672

Expenses
Electric utility		418,254			632,725			848,982			1,205,631
Bank		69,993			116,942			134,904			199,423
Other		2,599			2,786			6,099			6,270

		490,846			752,453			989,985			1,411,324

Operating income (loss)
Electric utility		32,163			55,396			63,232			106,379
Bank		5,506			(30,992	)		22,627			(7,629	)
Other		(2,614	)		(2,802	)		(6,146	)		(6,402	)

		35,055			21,602			79,713			92,348

Interest expense–other than on deposit liabilities and other bank borrowings		(17,910	)		(18,186	)		(35,743	)		(37,435	)
Allowance for borrowed funds used during construction		1,727			835			3,349			1,597
Allowance for equity funds used during construction		4,120			2,105			7,725			4,006

Income before income taxes		22,992			6,356			55,044			60,516
Income taxes		7,040			747			18,224			20,467

Net income		15,952			5,609			36,820			40,049
Less net income attributable to noncontrolling interest - preferred stock of subsidiaries		473			473			946			946

Net income for common stock	$	15,479		$	5,136		$	35,874		$	39,103

Basic earnings per common share	$	0.17		$	0.06		$	0.39		$	0.47

Diluted earnings per common share	$	0.17		$	0.06		$	0.39		$	0.47

Dividend per common share	$	0.31		$	0.31		$	0.62		$	0.62

Weighted-average number of common shares outstanding		91,384			84,052			90,996			83,762
Dilutive effect of stock-based compensation		110			103			92			60

Adjusted weighted-average shares		91,494			84,155			91,088			83,822


Ratio of earnings to fixed charges (SEC method)
Excluding interest on ASB deposits								2.14			1.75

Including interest on ASB deposits								1.77			1.52

For the three and six months ended June 30, 2009, under the two-class method of computing basic and diluted earnings per share, distributed earnings were $0.31 and $0.62 per share, respectively, and undistributed losses were $0.14 and $0.23 per share, respectively, for both unvested restricted stock awards and unrestricted common stock. For the three and six months ended June 30, 2008, under the two-class method of computing basic and diluted earnings per share, distributed earnings were $0.31 and $0.62 per share, respectively, and undistributed losses were $0.25 and $0.15 per share, respectively, 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)	June 30, 2009			December 31, 2008
Assets
Cash and equivalents	$	265,143		$	182,903
Federal funds sold		788			532
Accounts receivable and unbilled revenues, net		212,358			300,666
Available-for-sale investment and mortgage-related securities		621,740			657,717
Investment in stock of Federal Home Loan Bank of Seattle		97,764			97,764
Loans receivable, net		3,852,605			4,206,492
Property, plant and equipment, net of accumulated depreciation of $1,908,140 and $1,851,813		3,026,621			2,907,376
Regulatory assets		531,708			530,619
Other		317,747			328,823
Goodwill, net		82,190			82,190

	$	9,008,664		$	9,295,082

Liabilities and stockholders’ equity
Liabilities
Accounts payable	$	162,836		$	183,584
Deposit liabilities		4,168,708			4,180,175
Short-term borrowings—other than bank		55,000			—
Other bank borrowings		388,858			680,973
Long-term debt, net—other than bank		1,214,733			1,211,501
Deferred income taxes		159,069			143,308
Regulatory liabilities		300,450			288,602
Contributions in aid of construction		314,369			311,716
Other		808,602			871,476

		7,572,625			7,871,335


Stockholders’ equity
Common stock, no par value, authorized 200,000,000 shares; issued and outstanding: 91,561,514 shares and 90,515,573 shares		1,246,828			1,231,629
Retained earnings		194,018			210,840
Accumulated other comprehensive loss, net of tax benefits		(39,100	)		(53,015	)

Common stock equity		1,401,746			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

		1,436,039			1,423,747

	$	9,008,664		$	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			Accumulated other comprehensive			Noncontrolling interest: cumulative preferred stock			Total
(in thousands, except per share amounts)	Shares	Amount		earnings			loss			of subsidiaries			Total
Balance, December 31, 2008	90,516	$	1,231,629	$	210,840		$	(53,015	)	$	34,293		$	1,423,747
Cumulative effect of adoption of FSP FAS 115-2 and FAS 124-2, net of taxes of $2,497	—		—		3,781			(3,781	)		—			—
Comprehensive income:
Net income	—		—		35,874			—			946			36,820
Net unrealized gains (losses) on securities:
Net unrealized gains on securities arising during the period, net of taxes of $14,237	—		—		—			21,561			—			21,561
Net unrealized losses related to factors other than credit during the period, net of tax benefits of $5,147	—		—		—			(7,794	)		—			(7,794	)
Less: reclassification adjustment for net realized losses included in net income, net of tax benefits of $2,202	—		—		—			3,335			—			3,335
Retirement benefit plans:
Amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes of $3,718	—		—		—			5,827			—			5,827
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits of $3,333	—		—		—			(5,233	)		—			(5,233	)

Comprehensive income	—		—		35,874			17,696			946			54,516

Issuance of common stock, net	1,046		15,199		—			—			—			15,199
Common stock dividends ($0.62 per share)	—		—		(56,477	)		—			—			(56,477	)
Preferred stock dividends	—		—		—			—			(946	)		(946	)

Balance, June 30, 2009	91,562	$	1,246,828	$	194,018		$	(39,100	)	$	34,293		$	1,436,039


Balance, December 31, 2007	83,432	$	1,072,101	$	225,168		$	(21,842	)	$	34,293		$	1,309,720
Comprehensive income:
Net income	—		—		39,103			—			946			40,049
Net unrealized losses on securities:
Net unrealized losses on securities arising during the period, net of tax benefits of $2,847	—		—		—			(4,312	)		—			(4,312	)
Less: reclassification adjustment for net realized losses included in net income, net of tax benefits of $6,915	—		—		—			10,473			—			10,473
Retirement benefit plans:
Amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes of $1,848	—		—		—			2,916			—			2,916
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits of $1,668	—		—		—			(2,618	)		—			(2,618	)

Comprehensive income	—		—		39,103			6,459			946			46,508

Issuance of common stock, net	1,214		27,847		—			—			—			27,847
Common stock dividends ($0.62 per share)	—		—		(51,996	)		—			—			(51,996	)
Preferred stock dividends	—		—		—			—			(946	)		(946	)

Balance, June 30, 2008	84,646	$	1,099,948	$	212,275		$	(15,383	)	$	34,293		$	1,331,133

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

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)


Six months ended June 30	2009			2008
(in thousands)
Cash flows from operating activities
Net income	$	36,820		$	40,049
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment		76,999			75,733
Other amortization		2,484			4,203
Provision for loan losses		21,800			2,055
Loans receivable originated and purchased, held for sale		(291,500	)		(114,591	)
Proceeds from sale of loans receivable, held for sale		322,692			124,526
Net loss (gain) on sale of investment and mortgage-related securities		(44	)		17,388
Other-than-temporary impairment of available-for-sale mortgage-related securities		5,581			—
Changes in deferred income taxes		3,973			(585	)
Changes in excess tax benefits from share-based payment arrangements		318			(613	)
Allowance for equity funds used during construction		(7,725	)		(4,006	)
Changes in assets and liabilities
Decrease (increase) in accounts receivable and unbilled revenues, net		88,308			(28,564	)
Decrease (increase) in fuel oil stock		22,383			(69,254	)
Increase (decrease) in accounts payable		(20,748	)		45,874
Changes in prepaid and accrued income taxes and utility revenue taxes		(56,397	)		(68,490	)
Changes in other assets and liabilities		(24,633	)		(6,327	)

Net cash provided by operating activities		180,311			17,398

Cash flows from investing activities
Available-for-sale investment and mortgage-related securities purchased		(190,095	)		(376,809	)
Principal repayments on available-for-sale investment and mortgage-related securities		248,109			329,669
Proceeds from sale of available-for-sale investment and mortgage-related securities		44			1,291,609
Net decrease (increase) in loans held for investment		305,381			(29,359	)
Capital expenditures		(175,092	)		(101,976	)
Contributions in aid of construction		4,917			7,263
Other		86			750

Net cash provided by investing activities		193,350			1,121,147

Cash flows from financing activities
Net decrease in deposit liabilities		(11,467	)		(76,790	)
Net increase in short-term borrowings with original maturities of three months or less		55,000			130,172
Net decrease in retail repurchase agreements		(24,592	)		(20,380	)
Proceeds from other bank borrowings		310,000			508,584
Repayments of other bank borrowings		(577,517	)		(1,662,119	)
Proceeds from issuance of long-term debt		3,168			14,802
Repayment of long-term debt		—			(50,000	)
Changes in excess tax benefits from share-based payment arrangements		(318	)		613
Net proceeds from issuance of common stock		8,786			15,473
Common stock dividends		(51,127	)		(41,497	)
Preferred stock dividends of noncontrolling interest		(946	)		(946	)
Decrease in cash overdraft		(962	)		(8,582	)
Other		(1,190	)		477

Net cash used in financing activities		(291,165	)		(1,190,193	)

Net increase (decrease) in cash and equivalents and federal funds sold		82,496			(51,648	)
Cash and equivalents and federal funds sold, beginning of period		183,435			209,855

Cash and equivalents and federal funds sold, end of period	$	265,931		$	158,207

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 filed in HEI Exhibit 99.1 to HEI’s Form 8-K dated June 9, 2009 and the unaudited consolidated financial statements and the notes thereto in HEI’s Quarterly Report on SEC Form 10-Q for the quarter ended March 31, 2009.

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 June 30, 2009 and December 31, 2008, the results of its operations for the three and six months ended June 30, 2009 and 2008 and cash flows for the six months ended June 30, 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 June 30, 2009
Revenues from external customers	$	450,381	$	75,499		$	21		$	525,901
Intersegment revenues (eliminations)		36		—			(36	)		—

Revenues		450,417		75,499			(15	)		525,901

Profit (loss)*		24,666		5,482			(7,156	)		22,992
Income taxes (benefit)		8,672		1,461			(3,093	)		7,040

Net income (loss)		15,994		4,021			(4,063	)		15,952
Less net income attributable to noncontrolling interest – preferred stock of HECO and its subsidiaries		499		—			(26	)		473

Net income (loss) for common stock		15,495		4,021			(4,037	)		15,479

Six months ended June 30, 2009
Revenues from external customers		912,142		157,531			25			1,069,698
Intersegment revenues (eliminations)		72		—			(72	)		—

Revenues		912,214		157,531			(47	)		1,069,698

Profit (loss)*		47,749		22,574			(15,279	)		55,044
Income taxes (benefit)		17,124		7,671			(6,571	)		18,224

Net income (loss)		30,625		14,903			(8,708	)		36,820
Less net income attributable to noncontrolling interest – preferred stock of HECO and its subsidiaries		998		—			(52	)		946

Net income (loss) for common stock		29,627		14,903			(8,656	)		35,874

Assets (at June 30, 2009)		3,876,982		5,120,269			11,413			9,008,664

Three months ended June 30, 2008
Revenues from external customers	$	688,087	$	85,950		$	18		$	774,055
Intersegment revenues (eliminations)		34		—			(34	)		—

Revenues		688,121		85,950			(16	)		774,055

Profit (loss)*		44,828		(31,014	)		(7,458	)		6,356
Income taxes (benefit)		16,897		(12,921	)		(3,229	)		747

Net income (loss)		27,931		(18,093	)		(4,229	)		5,609
Less net income attributable to noncontrolling interest – preferred stock of HECO and its subsidiaries		499		—			(26	)		473

Net income (loss) for common stock		27,432		(18,093	)		(4,203	)		5,136

Six months ended June 30, 2008
Revenues from external customers		1,311,936		191,794			(58	)		1,503,672
Intersegment revenues (eliminations)		74		—			(74	)		—

Revenues		1,312,010		191,794			(132	)		1,503,672

Profit (loss)*		85,133		(7,673	)		(16,944	)		60,516
Income taxes (benefit)		32,118		(4,156	)		(7,495	)		20,467

Net income (loss)		53,015		(3,517	)		(9,449	)		40,049
Less net income attributable to noncontrolling interest – preferred stock of HECO and its subsidiaries		998		—			(52	)		946

Net income (loss) for common stock		52,017		(3,517	)		(9,397	)		39,103

Assets (at June 30, 2008)		3,586,441		5,585,278			10,477			9,182,196

*	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, contingencies and subsequent events, see pages 23 through 52.

4 • Bank subsidiary

Selected financial information

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

Consolidated Statements of Income Data (unaudited)


	Three months ended June 30						Six months ended June 30
(in thousands)	2009			2008			2009			2008
Interest and dividend income
Interest and fees on loans	$	55,363		$	61,747		$	113,455		$	125,212
Interest and dividends on investment and mortgage-related securities		7,143			22,729			14,819			47,180

		62,506			84,476			128,274			172,392

Interest expense
Interest on deposit liabilities		9,902			15,619			21,467			33,839
Interest on other borrowings		2,241			16,265			5,505			35,414

		12,143			31,884			26,972			69,253

Net interest income		50,363			52,592			101,302			103,139
Provision for loan losses		13,500			1,155			21,800			2,055

Net interest income after provision for loan losses		36,863			51,437			79,502			101,084

Noninterest income
Fees from other financial services		6,443			5,413			12,362			12,236
Fee income on deposit liabilities		7,462			6,767			14,173			13,561
Fee income on other financial products		1,628			1,639			2,672			3,443
Net gains (losses) on available-for-sale securities (includes impairment losses of $5,581, consisting of $18,522 of total other-than- temporary impairment losses, net of $12,941 of non-credit losses recognized in other comprehensive income, for the quarter and six months ended June 30, 2009)		(5,537	)		(18,323	)		(5,537	)		(17,388	)
Other income		2,997			5,978			5,587			7,550

		12,993			1,474			29,257			19,402

Noninterest expense
Compensation and employee benefits		17,991			19,039			37,351			37,279
Occupancy		5,922			5,390			11,051			10,787
Equipment		2,540			3,221			5,330			6,335
Services		3,801			4,170			7,219			9,843
Data processing		3,481			2,609			6,668			5,225
Loss on early extinguishment of debt		60			39,843			101			39,843
Other expense		10,579			9,653			18,465			18,847

		44,374			83,925			86,185			128,159

Income (loss) before income taxes		5,482			(31,014	)		22,574			(7,673	)
Income taxes (benefit)		1,461			(12,921	)		7,671			(4,156	)

Net income (loss)	$	4,021		$	(18,093	)	$	14,903		$	(3,517	)

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

Consolidated Balance Sheets Data (unaudited)


(in thousands)	June 30, 2009			December 31, 2008
Assets
Cash and equivalents	$	254,170		$	168,766
Federal funds sold		788			532
Available-for-sale investment and mortgage-related securities		621,740			657,717
Investment in stock of Federal Home Loan Bank of Seattle		97,764			97,764
Loans receivable, net		3,852,605			4,206,492
Other		211,012			223,659
Goodwill, net		82,190			82,190

	$	5,120,269		$	5,437,120


Liabilities and stockholder’s equity
Deposit liabilities–noninterest-bearing	$	750,487		$	701,090
Deposit liabilities–interest-bearing		3,418,221			3,479,085
Other borrowings		388,858			680,973
Other		86,743			98,598

		4,644,309			4,959,746


Common stock		329,130			328,162
Retained earnings		181,135			197,235
Accumulated other comprehensive loss, net of tax benefits		(34,305	)		(48,023	)

		475,960			477,374

	$	5,120,269		$	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 $212 million and $177 million, respectively, as of June 30, 2009 and $241 million and $440 million, respectively, as of December 31, 2008.

As of June 30, 2009, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.2 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. The $35.6 million is comprised of: (1) realized losses on the sale of mortgage-related securities and agency notes of $19.3 million included in “Noninterest income-Gain (loss) on sale of securities,” (2) fees associated with the early retirement of other bank borrowings of $39.8 million included in “Noninterest expense-Loss on early extinguishment of debt” and (3) income tax benefits of $23.5 million included in “Income taxes.” 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.

Investment and mortgage-related securities portfolio

Available-for-sale securities

The following table details the amortized cost basis and aggregate fair value by major security type at June 30, 2009:


June 30, 2009
(in thousands)	Cost		Gross unrealized gains		Gross unrealized losses			Fair value
U.S. Treasury and U.S. agency debentures	$	33,936	$	16	$	(101	)	$	33,851
Municipal bonds		6,307		6		(40	)		6,273
Mortgage-related securities:
Federal agencies		339,195		7,441		(35	)		346,601
Private-issue		275,018		20		(40,023	)		235,015

	$	654,456	$	7,483	$	(40,199	)	$	621,740

The following table details the contractual maturities and yields of available-for-sale securities. All positions with variable maturities (e.g. callable debentures and mortgage backed securities) are disclosed based upon the bond’s contractual maturity. Actual average maturities may be substantially shorter than those detailed below.


June 30, 2009
	Total book value		Weighted average Yield (%)	Maturity<1 year			Maturity 1-5 years			Maturity 5-10 years			Maturity>10 years
(dollars in thousands)	Total book value		Weighted average Yield (%)	Book value		Yield (%)	Book value		Yield (%)	Book value		Yield (%)	Book value		Yield (%)
U.S. Treasury and U.S. agency debentures	$	33,936	0.80	$	—	—	$	33,936	0.80	$	—	—	$	—	—
Municipal bonds		6,307	1.38		5,007	1.15		1,300	2.27		—	—		—	—
Mortgage-related securities:
Federal agencies		339,195	4.14		—	—		543	7.00		139,650	3.95		199,002	4.26
Private-issue		275,018	5.15		—	—		—	—		32,747	4.21		242,271	5.28

	$	654,456	4.36	$	5,007	1.15	$	35,779	0.94	$	172,397	4.00	$	441,273	4.82

Gross unrealized losses and fair value

The following table details the gross unrealized losses and fair values for securities held in available for sale by duration of time in which positions have been held in a continuous loss position. Positions for which OTTIs have been identified are categorized based upon the point at which unrealized losses were identified, not the point at which write-downs have occurred.


June 30, 2009
	Less than 12 months					12 months or more					Total
(in thousands)	Gross unrealized losses			Fair value		Gross unrealized losses			Fair value		Gross unrealized losses			Fair value
U.S. Treasury and U.S. agency debentures	$	(101	)	$	19,975	$	—		$	—	$	(101	)	$	19,975
Municipal bonds		(40	)		4,967		—			—		(40	)		4,967
Mortgage-related securities:
Federal agencies		(35	)		7,697		—			—		(35	)		7,697
Private-issue		(845	)		16,527		(39,178	)		217,064		(40,023	)		233,591

	$	(1,021	)	$	49,166	$	(39,178	)	$	217,064	$	(40,199	)	$	266,230

The unrealized losses on ASB’s investments in U.S. Treasury and agency debentures and mortgage-related securities issued by federal agencies were caused by interest rate increases. The contractual terms of these investments do not permit the issuer to settle the securities at a price less than the amortized cost bases of the investments. Because ASB does not intend to sell the securities and it is not more likely than not that ASB will be required to sell the investments before recovery of their amortized costs bases, which may be at maturity, ASB does not consider these investments to be other-than-temporarily impaired at June 30, 2009.

The unrealized losses on ASB’s investments in municipal bonds are primarily driven by interest rates and not due to the credit of the securities. All municipal obligations held in this portfolio are of investment grade and have been reviewed based on the credit of the underlying issuer. Based upon ASB’s initial and ongoing review of these credits, ASB does not consider these investments to be other-than-temporarily impaired at June 30, 2009.

The unrealized losses on ASB’s investments in private-issue mortgage-related securities is exemplary of the credit pressures in that sector. Positions are regularly monitored to track delinquency pipelines/trends, prepayment speeds and realized losses. Marginal positions are reviewed using management’s expectations of loss severity, constant default rates and prepayment speeds based upon deal performance, collateral characteristics and cohort vintage performance. Exclusive of positions detailed below which have incurred OTTIs, because ASB does not intend to sell the securities and it is not more likely than not that ASB will be required to sell the investments before recovery of their amortized costs bases, which may be at maturity, ASB does not consider these investments to be other-than-temporarily impaired at June 30, 2009.

The fair values of ASB’s investment securities could continue to decline if the current economic environment continues to deteriorate. While the performance of ASB’s private-issue mortgage-related securities are intrinsically tied to the economy, excess leverage in that sector coupled with weak underwriting of recent vintages could also pressure ASB’s positions even if the economy recovers. Despite ASB’s best estimate expectation of performance of ASB’s positions, economic uncertainty coupled with a very fragile housing market could result in material OTTIs.

Other-than-temporary impaired securities

All securities are reviewed for impairment in accordance with FSP FAS 115-2 and FAS 124-2. Under these standards ASB’s intent to sell the security, the probability of more-likely-than-not being forced to sell the position prior to recovery of its cost basis and the probability of more likely-than-not recovering the amortized cost of the position was determined. Because of ASB’s intent to hold all positions determined to be other-than-temporarily impaired, credit losses, which are recognized in earnings, were quantified using the position’s pre-impairment discount rate and the net present value of these losses. Non-credit related impairments are reflected in other comprehensive income.

The following table reflects cumulative OTTIs of expected losses that have been recognized in earnings. The beginning balance relates to credit losses realized prior to April 1, 2009 on debt securities held by the entity at the end of the period. This initial balance includes the net impact of non-credit losses that were originally reported as losses as of December 31, 2008 and were subsequently recharacterized from retained earnings as a result of the adoption of FSP FAS 115-2 and FAS 124-2. Additions to this balance include new securities in which initial OTTIs have been identified and incremental increases of OTTIs of positions that had already taken similar impairments.


(in thousands)	June 30, 2009
Balance, beginning of period	$	1,486
Additions:
Initial credit impairments		2,209
Subsequent credit impairments		3,372

Balance, end of period	$	7,067

Positions which management identified as credit related OTTIs for the first time this quarter include two fixed rate private-issue mortgage-related securities. Both positions are front sequential collateralized mortgage obligations one backed by prime collateral and the other backed by Alt-A collateral. One position which management had previously identified as other-than-temporary impaired at the end of 2008, had its book value increased $6.3 million at the beginning of the second quarter of 2009 upon adoption of FSP FAS 115-2 and FAS 124-2. Subsequent to that change, increasing delinquencies caused the increase in loss estimates and realized

losses as a result of credit. Credit related losses for private-issue mortgage-related securities are determined through management’s estimation of various inputs which impact the generation of future cash flows. Forward projections of economic activity and national housing market trends impact vectors used in this assessment. All estimates are determined based on specific characteristics of each pool performance and security structure:

•

Prepayment speeds – prepayment speed estimates are based upon historic performance, comparable collateral trends and refinance ability of borrowers. Vector constant prepayment rate (CPR) assumptions within the first 24 months start in a range of 6-9 CPR and average between 13.50 to 14.83 CPR for life speed projections.

•

Credit support – current levels of subordination that absorb credit losses of ASB tranches are considered. Current credit support as a % tranche range from 4.85% to 5.48%.

•

Gross losses % current balance – this ratio provides management’s gross expectation of loss divided by the current remaining balance held. Factors which impact these losses include the current/future delinquency pipeline, historical performance, performance of peer collateral and specific collateral characteristics which include geographic concentration, FICO scores, and loan type. Gross loss as a % of current balance ranges from 27.41% to 1.23%. The weighted average of these bonds is 15.99%.

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 delayed the application of SFAS No. 157 to ASB’s non-financial assets and non-financial liabilities until the first quarter of 2009. FSP 157-3,” Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” and FSP 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,” were issued in October 2008 and April 2009, respectively, 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:


	June 30, 2009		Fair value measurements using
(in millions)	June 30, 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	$	622	$	—	$	622	$	—

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:


	June 30, 2009		Fair value measurements using
(in millions)	June 30, 2009		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
Loans	$	10.0	$	—	$	3.5	$	6.5

Specific reserves as of June 30, 2009 were $2.8 million and were included in loans receivable held for investment, net. For the six months ended June 30, 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 income and 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.

Federal Deposit Insurance Corporation (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. Financial institution failures have significantly increased the DIF’s loss provisions, resulting in declines 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 were 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 of deposits. 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 of deposits. 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 assessment rate was 13 basis points of deposits, or $1.3 million, for the quarter ended March 31, 2009 and 14 basis points of deposits, or $1.5 million, for the quarter ended June 30, 2009, compared to an assessment rate of 5 basis points of deposits, or $0.1 million (net of a one-time assessment credit), for the quarter ended March 31, 2008 and 5 basis points of deposits, or $0.2 million (net of a one-time assessment credit), for the quarter ended June 30, 2008. In May 2009, the board of directors of the FDIC voted to levy a special assessment on deposit institutions to build the DIF and restore public confidence in the banking system. The special assessment was 5 basis points on each institution’s total assets, minus its Tier 1 core capital, as of June 30, 2009. Based on the FDIC’s formula, ASB’s special assessment was $2.3 million and ASB recorded the charge in June 2009.

The FDIC may impose additional special assessments in the final two quarters of 2009 if it is deemed necessary to ensure the DIF ratio does not decline to a level that is close to zero or that could otherwise undermine public confidence in federal deposit insurance. The FDIC chairman has commented that, at worst, there may be a similar five basis points assessment in the fourth quarter of 2009, but management cannot predict with certainty the timing or amounts of any additional assessments.

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. In May 2009, the FDIC extended the temporary increase in federal deposit insurance coverage through December 31, 2013. The legislation provides that the basic deposit insurance coverage limit will return to $100,000 after December 31, 2013 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 Transaction Account 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 six months of 2009, HECO contributed $15.7 million and HEI contributed $0.7 million to their respective retirement benefit plans, compared to $4.8 million and $0.4 million, respectively, in the first six months of 2008. The Company’s current estimate of contributions to its retirement benefit plans in 2009 is $27 million ($26 million to be made by the utilities, nil by ASB and $1 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 six months of 2009, the Company’s defined benefit retirement plans’ assets generated a return, net of investment management fees, of 7.0%. The market value of the defined benefit retirement plans’ assets as of June 30, 2009 was $761 million compared to $726 million at December 31, 2008, an increase of approximately $35 million.

The components of net periodic benefit cost were as follows:


	Three months ended June 30												Six months ended June 30
	Pension benefits						Other benefits						Pension benefits						Other benefits
(in thousands)	2009 (1)			2008 (1)			2009			2008			2009 (1)			2008 (1)			2009			2008
Service cost	$	6,388		$	6,989		$	1,171		$	1,182		$	12,729		$	13,845		$	2,227		$	2,347
Interest cost		15,514			14,915			2,838			2,790			31,052			29,791			5,685			5,628
Expected return on plan assets		(14,295	)		(18,269	)		(2,222	)		(2,742	)		(28,571	)		(36,501	)		(4,437	)		(5,482	)
Amortization of unrecognized transition obligation		—			1			784			784			1			2			1,569			1,569
Amortization of prior service cost (credit)		(95	)		(99	)		4			4			(188	)		(189	)		7			7
Recognized actuarial loss		3,964			1,691			107			—			7,933			3,381			223			—

Net periodic benefit cost		11,476			5,228			2,682			2,018			22,956			10,329			5,274			4,069
Impact of PUC D&Os		(4,107	)		1,547			(407	)		230			(8,198	)		3,204			(732	)		423

Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	7,369		$	6,775		$	2,275		$	2,248		$	14,758		$	13,533		$	4,542		$	4,492

(1)

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. Thus, there are no amounts for ASB employees for certain components (service cost for benefit accruals, amortization of unrecognized transition obligation and amortization of prior service cost (credit)).

The Company recorded retirement benefits expense of $15 million and $14 million in the first six months of 2009 and 2008, respectively, and charged the remaining amounts primarily to electric utility plant.

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

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 effective January 1, 2008. On May 7, 2009, the account balances of ASB participants were transferred from HEI’s retirement savings plan to account balances in the newly created ASB 401(k) Plan. $41 million in assets was transferred in-kind between plans. On May 15, 2009, ASB contributed $2.1 million to fund the discretionary employer profit sharing (AmeriShare) portion of the plan for the 2008 plan year. This AmeriShare contribution was allocated pro-rata to accounts of eligible participants based on a flat 4% percent of eligible pay. This 4% contribution percentage was determined at year-end based on ASB’s performance and achievement of financial goals for 2008. For the first six months of 2009 and 2008, ASB’s total expense for its employees participating in the HEI retirement savings plan and the ASB 401(k) Plan combined was $1.3 million and $2.2 million, respectively, and cash contributions were $3.0 million and $0.9 million, respectively.

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 June 30, 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 awards generally become unrestricted three to five years after the date of grant and are forfeited for terminations of employment during the vesting period, except for terminations by reason of death, disability or termination without cause which allow for pro-rata vesting. Restricted stock awards 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 and are forfeited for terminations of employment during the vesting period, except for terminations due to death, disability and retirement which allow for pro-rata vesting. 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 shares granted under the 2009-2011 Long-Term Incentive Plan (LTIP) are based on the achievement of certain financial goals and vest at the end of the three-year performance period. LTIP is forfeited for terminations of employment during the vesting period, except for terminations due to death, disability and retirement which allow for pro-rata vesting based upon completed months of service after a minimum of 12 months of service in the performance period. Compensation expense for the performance shares portion of the 2009-2011 LTIP award has been recognized in accordance with the fair-value based measurement method of accounting for performance shares.

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 June 30			Six months ended June 30
($ in millions)	2009	2008		2009	2008
Share-based compensation expense ¹	—	(0.1	)	0.4	0.2
Income tax benefit	—	—		0.1	—

The Company has not capitalized any share-based compensation cost. For the second quarter of 2009, the estimated forfeiture rates were 41.0% for restricted stock awards, 5.9% for restricted stock units, and 10.3% for performance shares. In the second quarter of 2009, the cumulative effect of the change in estimated forfeitures was recorded, resulting in nil for the share-based compensation expense in 2009.

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


June 30, 2009			Outstanding & Exercisable
Year of grant	Range of exercise prices		Number of options	Weighted-average remaining contractual life	Weighted-average exercise price
2000	$	14.74	46,000	0.8	$	14.74
2001		17.96	65,000	1.8		17.96
2002		21.68	122,000	2.6		21.68
2003		20.49	141,500	3.2		20.49

	$	14.74 – 21.68	374,500	2.5	$	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 June 30, 2009, all NQSO’s outstanding were exercisable and had an aggregate intrinsic value (including dividend equivalents) of $0.9 million.

NQSO activity and statistics are summarized as follows:


	Three months ended June 30			Six months ended June 30
($ in thousands, except prices)	2009	2008		2009	2008
Shares granted/forfeited/vested	—		—	—		—
Aggregate fair value of vested shares	—		—	—		—
Shares expired	1,000		—	1,000		—
Shares exercised	—		200,300	—		212,300
Weighted-average exercise price	—	$	19.56	—	$	19.61
Cash received from exercise	—	$	3,918	—	$	4,164
Intrinsic value of shares exercised ¹	—	$	2,101	—	$	2,185
Tax benefit realized for the deduction of exercises	—	$	818	—	$	851
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:


June 30, 2009			Outstanding and Exercisable
Year of grant	Range of exercise prices		Number of shares underlying SARs	Weighted-average remaining contractual life	Weighted-average exercise price
2004	$	26.02	150,000	3.8	$	26.02
2005		26.18	330,000	4.2		26.18

	$	26.02 – 26.18	480,000	4.1	$	26.13

As of December 31, 2008, the shares underlying SARs outstanding totaled 791,000, with a weighted-average exercise price of $26.12. As of June 30, 2009, all SARS outstanding were exercisable and had no intrinsic value.

SARs activity and statistics are summarized as follows:


	Three months ended June 30				Six months ended June 30
($ in thousands, except prices)	2009		2008		2009		2008
Shares granted		—		—		—		—
Shares forfeited		—		30,000		6,000		30,000
Shares expired		305,000		—		305,000		—
Shares vested		228,000		46,000		228,000		61,000
Aggregate fair value of vested shares	$	1,354	$	242	$	1,354	$	329
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.

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 six months ended June 30, 2009 and 2008 a total of 3,143 and 6,125 dividend equivalent shares, respectively, for NQSO and SAR grants were distributed to SOIP participants. 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 June 30, 2009 and December 31, 2008, restricted stock award shares outstanding totaled 134,000 and 160,500, with a weighted-average grant date fair value of $25.50 and $25.51, respectively. The grant date fair value 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 June 30				Six months ended June 30
($ in thousands)	2009		2008		2009		2008
Shares vested		3,257		—		3,851		—
Grant date fair value	$	80		—	$	94		—
Shares forfeited		1,243		12,500		22,649		18,500
Grant date fair value	$	32	$	323	$	583	$	480
Shares granted		—		42,700		—		42,700
Grant date fair value		—	$	1,055		—	$	1,055

The tax benefits realized for the tax deductions related to restricted stock awards were $58,000 and $47,000 for the first six months of 2009 and 2008, respectively.

As of June 30, 2009, there was $1.3 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 2.2 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 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 June 30, 2009, there were 70,500 restricted stock units outstanding, none were vested and none were forfeited.

As of June 30, 2009, there was $1.0 million of total unrecognized compensation cost related to the nonvested restricted stock units. The cost is expected to be recognized over a period of 3.6 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 (TRS) as a percentile to the Edison Electric Institute Index over the three-year period and return on average common equity (ROACE) targets.

The grant date fair value of the performance shares linked to TRS was $0.5 million. The grant date fair value was determined using a Monte Carlo simulation model utilizing actual information for the common shares of HEI and its peers for the period from January 1, 2009 to the February 20, 2009 grant date and estimated future stock volatility and dividends of HEI and its peers. The expected stock volatility assumptions for HEI and its peer group were based on the three-year historic stock volatility, and the annual dividend yield assumptions were based on dividend yields calculated on the basis of daily stock prices over the same 3-year historical period. The following table summarizes the assumptions used to determine the fair value of the performance shares linked to TRS and the resulting fair value of performance shares granted:


Risk-free interest rate	1.30	%
Expected life in years	3
Expected volatility	23.7	%
Dividend yield	4.53	%
Range of expected volatility for Peer Group	20.8% to 46.9	%
Grant date fair value (per share)	$13.08

As of June 30, 2009, there were 36,198 shares underlying the performance share awards with the TRS condition outstanding, based on target performance levels and $0.4 million of total unrecognized compensation cost. The cost is expected to be recognized over a remaining period of 2.5 years.

The grant date fair value of the performance shares linked to ROACE was $0.3 million. The grant date fair value of $13.34 per share was the average price of HEI common stock on grant date less the present value of expected dividends to be paid over the performance period, discounted by the risk-free interest rate based on the U.S. Treasury yield at the date of grant.

As of June 30, 2009, there were 24,131 shares underlying the performance share awards with the ROACE condition outstanding, based on target performance levels and $0.2 million of total unrecognized compensation cost. The cost is expected to be recognized over a period of 2.5 years.

7 • Commitments and contingencies

See Note 4, “Bank subsidiary,” above and Note 5, “Commitments and contingencies,” of HECO’s “Notes to Consolidated Financial Statements.”

8 • Cash flows

Supplemental disclosures of cash flow information. For the six months ended June 30, 2009 and 2008, the Company paid interest (net of amounts capitalized and including bank interest) to non-affiliates amounting to $52 million and $104 million, respectively.

For the six months ended June 30, 2009 and 2008, the Company paid income taxes amounting to $12 million and $91 million, respectively. The significant decrease in taxes paid was due primarily to the differences in the taxes due with the extensions for tax years 2008 and 2007 and in the estimated tax payments due for the first half of 2009 and the first half of 2008. 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. This larger taxable income also resulted in disproportionately higher estimated tax payments for the first two quarters of 2008 versus the first two quarters of 2009.

Supplemental disclosures of noncash activities. Noncash increases in common stock for director and officer compensatory plans of the Company were $1.2 million and $1.3 million for the six months ended June 30, 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 and $10 million for the first six months of 2009 and 2008, respectively. 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. Effective May 7, 2009, HEI began satisfying the requirements of the ASB 401(k) Plan by acquiring for cash its common shares through open market purchases.

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 adopted the FSPs in the second quarter of 2009 and provided additional disclosures regarding fair value measurements and OTTIs. 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 reclassified $3.8 million of the previously recognized impairment to accumulated other comprehensive income.

Subsequent events. In May 2009, the FASB issued SFAS No. 165, “Subsequent Events,” which establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS No. 165 provides: (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. The Company adopted SFAS No. 165 in the second quarter of 2009. See Note 11.

Variable interest entities. In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R),” which eliminates exceptions to consolidating qualifying special-purpose entities (QSPEs), contains new criteria for determining the primary beneficiary, and increases the frequency of required reassessments to determine whether a company is the primary beneficiary of a variable interest entity (VIE). It also clarifies, but does not significantly change, the characteristics that identify a VIE. The Company will adopt SFAS No. 167 in the first quarter of 2010 and has not yet determined the impact of adoption.

FASB Codification. In June 2009, the FASB issued SFAS No. 168, “FASB Accounting Standards Codification^TM and the Hierarchy of Generally Accepted Accounting Principles,” which establishes the Codification as the single source of authoritative U.S. generally accepted accounting principles (U.S. GAAP) recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants. The Company will adopt SFAS No. 168 in the third quarter of 2009 and will change or eliminate citations for previous standards (other than SEC citations) in future financial statements and other documents.

10 • Fair value of financial instruments

Fair value estimates are based on the price that would be received to sell an asset, or paid upon the transfer of a liability, in an orderly transaction between market participants at the measurement date. The fair value estimates are generally determined based on assumptions that market participants would use in pricing the asset or liability and are based on market data obtained from independent sources. However, in certain cases, the Company uses its own assumptions about market participant assumptions based on the best information available in the circumstances. These valuations are estimates at a specific point in time, based on relevant market information, information about the financial instrument and judgments regarding future expected loss experience,

economic conditions, risk characteristics of various financial instruments and other factors. These estimates do not reflect any premium or discount that could result if the Company were to sell its entire holdings of a particular financial instrument at one time. Because no market exists for a portion of the Company’s financial instruments, fair value estimates cannot be determined with precision. Changes in the underlying assumptions used, including discount rates and estimates of future cash flows, could significantly affect the estimates. Fair value estimates are provided for certain financial instruments without attempting to estimate the value of anticipated future business and the value of assets and liabilities that are not considered financial instruments. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates and have not been considered.

The Company used the following methods and assumptions to estimate the fair value of each applicable class of financial instruments for which it is practicable to estimate that value:

Cash and equivalents, federal funds sold and short-term borrowings—other than bank. The carrying amount approximated fair value because of the short maturity of these instruments.

Investment and mortgage-related securities. Fair value was based on observable inputs using market-based valuation techniques.

Loans receivable. For residential real estate loans, fair value is calculated by discounting estimated cash flows using discount rates based on current industry pricing for loans with similar contractual characteristics.

For other types of loans, fair value is estimated by discounting contractual cash flows using discount rates that reflect current industry pricing for loans with similar characteristics and remaining maturity. Where industry pricing is not available, discount rates are based on ASB’s current pricing for loans with similar characteristics and remaining maturity.

The fair value of all loans were adjusted to reflect current assessments of loan collectibility.

Deposit liabilities. The fair value of demand deposits, savings accounts, and money market deposits was the amount payable on demand at the reporting date. The fair value of fixed-maturity certificates of deposit was estimated by discounting the future cash flows using the rates currently offered for deposits of similar remaining maturities.

Other bank borrowings. Fair value was estimated by discounting the future cash flows using the current rates available for borrowings with similar credit terms and remaining maturities.

Long-term debt. Fair value was obtained from a third-party financial services provider based on the current rates offered for debt of the same or similar remaining maturities.

Off-balance sheet financial instruments. The fair value of loans serviced for others was calculated by discounting expected net income streams using discount rates that reflect industry pricing for similar assets. Expected net income streams are estimated based on industry assumptions regarding prepayment speeds and income and expenses associated with servicing residential mortgage loans for others. The fair value of commitments to originate loans and unused lines of credit was estimated based on the primary market prices of new commitments and new lines of credit. The change in current primary market prices provided the estimate of the fair value of these commitments and unused lines of credit. The fair values of other off-balance sheet financial instruments (letters of credit) were estimated based on the fees currently charged to enter into similar agreements, taking into account the remaining terms of the agreements. Fair value of HECO-obligated preferred securities of trust subsidiaries was based on quoted market prices.

The estimated fair values of certain of the Company’s financial instruments were as follows:


	June 30, 2009				December 31, 2008
(in thousands)	Carrying or notional amount		Estimated fair value		Carrying or notional amount		Estimated fair value
Financial assets
Cash and equivalents	$	265,143	$	265,143	$	182,903	$	182,903
Federal funds sold		788		788		532		532
Available-for-sale investment and mortgage-related securities		621,740		621,740		657,717		657,717
Investment in stock of Federal Home Loan Bank of Seattle		97,764		97,764		97,764		97,764
Loans receivable, net		3,852,605		3,928,120		4,206,492		4,322,153
Financial liabilities
Deposit liabilities		4,168,708		4,180,695		4,180,175		4,197,429
Short-term borrowings—other than bank		55,000		55,000		—		—
Other bank borrowings		388,858		402,993		680,973		701,998
Long-term debt		1,214,733		1,077,225		1,211,501		949,170
Off-balance sheet items
HECO-obligated preferred securities of trust subsidiary		50,000		45,500		50,000		40,420

As of June 30, 2009 and December 31, 2008, loan commitments and unused lines and letters of credit had notional amounts of $1.2 billion and their estimated fair value on such dates was $0.2 million and $0.8 million, respectively. As of June 30, 2009 and December 31, 2008, loans serviced for others had notional amounts of $497.0 million and $307.6 million and the estimated fair value of the servicing rights for such loans was $4.2 million and $2.6 million, respectively.

11 • Subsequent events

The Company has evaluated subsequent events through August 7, 2009 (12:01 a.m.), the date the financial statements were issued.

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)


	Three months ended June 30						Six months ended June 30
(in thousands, except ratio of earnings to fixed charges)	2009			2008			2009			2008
Operating revenues	$	447,836		$	686,647		$	907,121		$	1,309,141

Operating expenses
Fuel oil		131,885			273,755			277,174			523,298
Purchased power		115,189			177,226			229,673			328,021
Other operation		63,181			59,422			125,578			115,001
Maintenance		29,431			23,990			55,594			47,603
Depreciation		36,425			35,401			72,849			70,835
Taxes, other than income taxes		41,975			62,371			87,710			119,857
Income taxes		8,727			17,094			17,271			32,472

		426,813			649,259			865,849			1,237,087

Operating income		21,023			37,388			41,272			72,054

Other income
Allowance for equity funds used during construction		4,120			2,105			7,725			4,006
Other, net		2,468			1,111			4,836			2,207

		6,588			3,216			12,561			6,213

Income before interest and other charges		27,611			40,604			53,833			78,267

Interest and other charges
Interest on long-term debt		11,945			11,810			23,857			23,534
Amortization of net bond premium and expense		682			639			1,357			1,270
Other interest charges		717			1,059			1,343			2,045
Allowance for borrowed funds used during construction		(1,727	)		(835	)		(3,349	)		(1,597	)

		11,617			12,673			23,208			25,252

Income before preferred stock dividends of HECO and subsidiaries		15,994			27,931			30,625			53,015
Less net income attributable to noncontrolling interest - preferred stock of subsidiaries		229			229			458			458

Income before preferred stock dividends of HECO		15,765			27,702			30,167			52,557
Preferred stock dividends of HECO		270			270			540			540

Net income for common stock	$	15,495		$	27,432		$	29,627		$	52,017

Ratio of earnings to fixed charges (SEC method)								2.54			3.90

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)	June 30, 2009			December 31, 2008
Assets
Utility plant, at cost
Land	$	51,408		$	42,541
Plant and equipment		4,419,824			4,277,499
Less accumulated depreciation		(1,796,263	)		(1,741,453	)
Construction in progress		293,812			266,628

Net utility plant		2,968,781			2,845,215

Current assets
Cash and equivalents		3,676			6,901
Customer accounts receivable, net		108,242			166,422
Accrued unbilled revenues, net		78,505			106,544
Other accounts receivable, net		7,716			7,918
Fuel oil stock, at average cost		55,332			77,715
Materials and supplies, at average cost		35,072			34,532
Prepayments and other		14,657			12,626

Total current assets		303,200			412,658

Other long-term assets
Regulatory assets		531,708			530,619
Unamortized debt expense		13,880			14,503
Other		59,413			53,114

Total other long-term assets		605,001			598,236

	$	3,876,982		$	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		299,210			299,214
Retained earnings		811,082			802,590
Accumulated other comprehensive income, net of income taxes		1,768			1,651

Common stock equity		1,197,447			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		1,231,740			1,223,135
Long-term debt, net		907,733			904,501

Total capitalization		2,139,473			2,127,636

Current liabilities
Short-term borrowings–nonaffiliates		55,000			—
Short-term borrowings–affiliate		45,604			41,550
Accounts payable		110,113			122,994
Interest and preferred dividends payable		16,158			15,397
Taxes accrued		158,565			220,046
Other		56,050			55,268

Total current liabilities		441,490			455,255

Deferred credits and other liabilities
Deferred income taxes		173,251			166,310
Regulatory liabilities		300,450			288,602
Unamortized tax credits		56,973			58,796
Retirement benefits liability		395,204			392,845
Other		55,772			54,949

Total deferred credits and other liabilities		981,650			961,502

Contributions in aid of construction		314,369			311,716

	$	3,876,982		$	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			Retained			Accumulated other comprehensive income			Cumulative preferred			Noncontrolling interest: cumulative preferred stock of			Total
(in thousands, except per share amounts)	Shares	Amount		(loss)			earnings			(loss)			stock			subsidiaries			Total
Balance, December 31, 2008	12,806	$	85,387	$	299,214		$	802,590		$	1,651		$	22,293		$	12,000		$	1,223,135
Comprehensive income:
Income before preferred stock dividends of HECO and subsidiaries	—		—		—			29,627			—			540			458			30,625
Retirement benefit plans:
Amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes of $3,408	—		—		—			—			5,350			—			—			5,350
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits of $3,333	—		—		—			—			(5,233	)		—			—			(5,233	)

Comprehensive income	—		—		—			29,627			117			540			458			30,742

Capital stock expense	—		—		(4	)		—			—			—			—			(4	)
Common stock dividends	—		—		—			(21,135	)		—			—			—			(21,135	)
Preferred stock dividends	—		—		—			—			—			(540	)		(458	)		(998	)

Balance, June 30, 2009	12,806	$	85,387	$	299,210		$	811,082		$	1,768		$	22,293		$	12,000		$	1,231,740


Balance, December 31, 2007	12,806	$	85,387	$	299,214		$	724,704		$	1,157		$	22,293		$	12,000		$	1,144,755
Comprehensive income:
Income before preferred stock dividends of HECO and subsidiaries	—		—		—			52,017			—			540			458			53,015
Retirement benefit plans:
Amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes of $1,741	—		—		—			—			2,733			—			—			2,733
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits of $1,668	—		—		—			—			(2,618	)		—			—			(2,618	)

Comprehensive income	—		—		—			52,017			115			540			458			53,130

Common stock dividends	—		—		—			(14,089	)		—			—			—			(14,089	)
Preferred stock dividends	—		—		—			—			—			(540	)		(458	)		(998	)

Balance, June 30, 2008	12,806	$	85,387	$	299,214		$	762,632		$	1,272		$	22,293		$	12,000		$	1,182,798

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)


Six months ended June 30	2009			2008
(in thousands)
Cash flows from operating activities
Income before preferred stock dividends of HECO and subsidiaries	$	30,625		$	53,015
Adjustments to reconcile income before preferred stock dividends of HECO and subsidiaries to net cash provided by operating activities
Depreciation of property, plant and equipment		72,849			70,835
Other amortization		5,502			4,303
Changes in deferred income taxes		7,264			(3,598	)
Changes in tax credits, net		(1,321	)		888
Allowance for equity funds used during construction		(7,725	)		(4,006	)
Changes in assets and liabilities
Decrease (increase) in accounts receivable		58,382			(26,612	)
Decrease (increase) in accrued unbilled revenues		28,039			(8,709	)
Decrease (increase) in fuel oil stock		22,383			(69,254	)
Increase in materials and supplies		(540	)		(2,704	)
Increase in regulatory assets		(10,564	)		(1,095	)
Increase (decrease) in accounts payable		(12,881	)		45,634
Change in prepaid and accrued income and utility revenue taxes		(61,259	)		(43,085	)
Changes in other assets and liabilities		(3,542	)		2,211

Net cash provided by operating activities		127,212			17,823

Cash flows from investing activities
Capital expenditures		(174,473	)		(99,924	)
Contributions in aid of construction		4,917			7,263
Other		—			733

Net cash used in investing activities		(169,556	)		(91,928	)

Cash flows from financing activities
Common stock dividends		(21,135	)		(14,089	)
Preferred stock dividends		(998	)		(998	)
Proceeds from issuance of long-term debt		3,168			14,802
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		59,054			88,636
Decrease in cash overdraft		(962	)		(8,582	)
Other		(8	)		—

Net cash provided by financing activities		39,119			79,769

Net increase (decrease) in cash and equivalents		(3,225	)		5,664
Cash and equivalents, beginning of period		6,901			4,678

Cash and equivalents, end of period	$	3,676		$	10,342

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 filed in HECO Exhibit 99.2 to HECO’s Form 8-K dated June 9, 2009 and the unaudited consolidated financial statements and the notes thereto in HECO’s Quarterly Report on SEC Form 10-Q for the quarter ended March 31, 2009.

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 June 30, 2009 and December 31, 2008 and the results of their operations for the three and six months ended June 30, 2009 and 2008 and their cash flows for the six months ended June 30, 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 June 30, 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 six months ended June 30, 2009 and 2008 each consisted of $1.7 million of interest income received from the 2004 Debentures; $1.6 million of distributions to holders of the Trust Preferred Securities; and $0.1 million of common dividends on the trust common securities to HECO. So long as the 2004 Trust Preferred Securities are outstanding, HECO is not entitled to receive any funds from Trust III other than pro rata distributions, subject to certain subordination provisions, on the trust common securities. In the event of a default by HECO in the performance of its obligations under the 2004 Debentures or under its Guarantees, or in the event HECO, HELCO or MECO elect to defer payment of interest on any of their respective 2004 Debentures, then

HECO will be subject to a number of restrictions, including a prohibition on the payment of dividends on its common stock.

Purchase power agreements. As of June 30, 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 six months ended June 30, 2009 totaled $230 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $67 million, $72 million, $30 million and $20 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. However, HECO and its subsidiaries’ revenue tax payments to the taxing authorities are based on the prior year’s revenues. For the six months ended June 30, 2009 and 2008, HECO and its subsidiaries included approximately $83 million and $115 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 six months of 2009, HECO and its subsidiaries contributed $15.7 million to their retirement benefit plans, compared to $4.8 million in the first six months of 2008. HECO and its subsidiaries’ current estimate of contributions to their retirement benefit plans in 2009 is $26 million, compared to contributions of $14 million in 2008. In addition, HECO and its subsidiaries expect to pay directly $0.7 million of benefits in 2009, compared to $0.1 million paid in 2008.

For the first six months of 2009, HECO and its subsidiaries’ defined benefit retirement plans’ assets generated a return, net of investment management fees, of 7.0%. The market value of the defined benefit retirement plan’s assets as of June 30, 2009 was $687 million compared to $655 million at December 31, 2008, an increase of approximately $32 million.

The components of net periodic benefit cost were as follows:


	Three months ended June 30												Six months ended June 30
	Pension benefits						Other benefits						Pension benefits						Other benefits
(in thousands)	2009			2008			2009			2008			2009			2008			2009			2008
Service cost	$	6,107		$	6,643		$	1,137		$	1,150		$	12,167		$	13,176		$	2,164		$	2,285
Interest cost		14,034			13,473			2,755			2,709			28,084			26,918			5,520			5,464
Expected return on plan assets		(12,693	)		(16,277	)		(2,183	)		(2,697	)		(25,366	)		(32,528	)		(4,361	)		(5,392	)
Amortization of unrecognized transition obligation		—			—			782			783			—			—			1,565			1,565
Amortization of prior service credit		(185	)		(190	)		—			—			(368	)		(381	)		—			—
Recognized actuarial loss (gain)		3,673			1,644			103			—			7,344			3,289			217			—

Net periodic benefit cost		10,936			5,293			2,594			1,945			21,861			10,474			5,105			3,922
Impact of PUC D&Os		(4,107	)		1,547			(407	)		230			(8,198	)		3,204			(732	)		423

Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	6,829		$	6,840		$	2,187		$	2,175		$	13,663		$	13,678		$	4,373		$	4,345

HECO and its subsidiaries recorded retirement benefits expense of $14 million in each of the first six months 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 require approval of the PUC in proceedings that 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. These changes to the RPS law were subsequently enacted when Act 155 was passed by the Hawaii legislature and signed into law by the Governor in 2009.

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. Such an Energy Efficiency Portfolio Standard was enacted as part of Act 155, which provided that the PUC shall establish the standards designed to achieve a reduction of 4,300 gigawatthours of electricity use statewide by 2030. The law also provides that the PUC shall establish interim goals for electricity use reduction to be achieved by 2015, 2020, and 2025, and may revise the 2030 standard by rule or order to maximize cost-effective, energy-efficiency programs and technologies and may establish incentives and penalties.

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 Renewable Energy Infrastructure Program (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.

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.

•

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.

•

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

•

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, panel hearings were held in April 2009 and opening and reply briefs were filed in June 2009. The procedural schedule calls for a PUC decision on FIT general principles in August 2009 and filing of proposed tariff sheets in September 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 and May 2009. Panel hearings at the PUC were completed on July 1, 2009 and the PUC has requested additional information from the parties, to which HECO is responding. Briefing by the parties is scheduled to be completed in September 2009.

In its 2009 test year rate case, HECO proposed to establish a revenue balancing account (RBA) to be effective upon the issuance of the interim D&O, but the PUC did not approve the proposal, pending the outcome of the decoupling proceeding. 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, however, HELCO and MECO were unable to file 2009 test year rate case applications. On July 17, 2009, MECO filed a Notice of Intent to file an application for a general rate case using a 2010 calendar test year on or after September 30, 2009 (but before January 1, 2010), and HELCO filed a Notice of Intent to file an application for a general rate case using a 2010 test year on or after November 25, 2009 (but before January 1, 2010).

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 in 2009 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 for approval at the end of April 2009 to the PUC, 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 an annual increase of $24.6 million, or 7.58%, 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 an annual increase of $70 million, a 4.96% increase over rates effective at the time of the interim decision ($78 million 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 an annual increase of $13 million, or a 3.7% increase.

As of June 30, 2009, HECO and its subsidiaries had recognized $198 million of revenues with respect to interim orders ($5 million related to interim orders regarding certain integrated resource planning costs and $193 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 June 30, 2009 noted in parentheses) include HECO’s Campbell Industrial Park (CIP) combustion turbine No. 1 (CT-1) and a transmission line ($164 million), HECO’s East Oahu Transmission Project ($43 million), HELCO’s ST-7 ($83 million) and a customer information system ($23 million).

CIP CT-1 and transmission line. HECO has built a new 110 MW simple cycle combustion turbine (CT) generating unit at CIP and has added 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). The CT completed all utility requirements for system operation on August 3, 2009. Plans are for the CT to be run primarily as a “peaking” unit and to be fueled by biodiesel at a later date, when a supply of biodiesel fuel becomes available.

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. Construction on the Project began in May 2008. In its 2009 test year rate case, HECO requested inclusion of CIP CT-1 costs in rate base when the unit is placed in service, but the PUC did not grant the request indicating that the record did not yet demonstrate that the unit would be in service by the end of 2009. Subsequently CIP CT-1 completed all utility requirements for system operation on August 3, 2009. HECO contends that the CIP CT-1 costs should be included in rate base in an interim decision and the final decision in the 2009 test year rate case.

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 June 30, 2009, HECO’s cost estimate for the Project (exclusive of the costs of the community benefit measures described above) was $193 million (of which $164 million had been incurred, including $8 million of AFUDC) and outstanding commitments for materials, equipment and outside services totaled $26 million. To the extent actual project costs are higher than the $163 million 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 June 30, 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 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 August 2009, the PUC denied approval of the amended HECO contract with Imperium GH and the related terminalling and trucking agreement, indicating that HECO did not satisfy the burden of proof that the contracts, the costs of which will be passed directly to the ratepayers, were reasonable, prudent and in the public interest. The PUC also stated it “remains strongly supportive of biofuels and other renewable energy resources. The commission’s decision herein is not intended to reflect a decision as to the prudency of biodiesel or the proposed biodiesel feedstock.” HECO intends to solicit new bids from biofuel suppliers for CIP CT-1. Consistent with the plan approved by the PUC in its May 2007 order approving the Project, during the unit’s initial period of commercial operation, it is undergoing performance testing using low sulfur diesel fuel in order to comply with the manufacturer’s warranties. This will be followed by testing using biofuels to obtain the data necessary for modification of the unit’s air permit. Also consistent with the PUC’s May 2007 order, HECO will be working with the PUC and Consumer Advocate to address contingency plans should there be a delay in securing a biofuel supplier for fuel to be used after the testing phase.

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 second phase is projected to be completed in 2013.

As of June 30, 2009, the accumulated costs recorded for the EOTP amounted to $43 million, including (i) $12 million of planning and permitting costs incurred prior to 2003, (ii) $11 million of planning, permitting and construction costs incurred after 2002 and (iii) $20 million for AFUDC. Management believes no adjustment to project costs is required as of June 30, 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.

On June 22, 2009, ST-7 was placed into service. As of June 30, 2009, HELCO’s cost estimate for ST-7 was $92 million (of which $83 million had been incurred and $9 million was estimated for ongoing peripheral work). HELCO intends to seek to recover the costs of ST-7 in HELCO’s next rate case application.

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.

Management believes no adjustment to project costs is required at June 30, 2009. However, 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. 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 into 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 June 30, 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 June 30, 2009, the remaining accrual (amounts expensed less amounts expended) for the Iwilei unit was $1.7 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 develop BART implementation plans and schedules in accordance with the amended regional haze rule by December 2007. If a state does not develop a BART implementation plan, the EPA is required to develop a federal implementation plan (FIP) by 2011. To date, Hawaii has not a developed an implementation plan. After Hawaii adopts its plan or the EPA issues an FIP, 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. On July 2, 2009, the EPA published in the Federal Register a notice of intent to issue an Information Collection Request (ICR) regarding coal-fired and oil-fired utility EGUs. The ICR is the first step in the regulatory process to develop the MACT standards for utility EGUs. The EPA states that the purpose of the ICR is (1) to identify categories of affected sources and (2) to define the emission level being achieved by the average of the top performing 12% of the existing sources. The CAA mandates the average of the top performing 12% of existing sources (i.e., units with the lowest HAP emission rates) as the MACT standard for existing sources. The ICR will be applicable to HECO steam units and will require providing existing fuel and emissions data to the EPA as well as emission testing at each of HECO’s steam generating plants on Oahu.

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 (RICE). 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., 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.

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.

In July 2007, the EPA had formally suspended the rule pending the outcome of legal challenges to 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 were subject to permit renewal in mid-2009. HECO timely submitted permit renewal applications for its facilities in 2009. The existing permits remain in force until renewals are issued. Renewable permits may be subject to new permit conditions to address cooling water intake requirements.

Apollo Energy Corporation/Tawhiri Power LLC. HELCO purchases energy generated at the Kamao’a wind farm pursuant to the Restated and Amended Power Purchase Contract for As-Available Energy (the RAC) dated October 13, 2004 between HELCO and Apollo Energy Corporation (Apollo), later assigned to Apollo’s affiliate, Tawhiri Power LLC (Tawhiri). The maximum ouput of the wind farm is 20 MW. By letter to HELCO dated June 15, 2009, Tawhiri requested binding arbitration as provided for under the provisions of the RAC on the issue of HELCO’s curtailment of the wind farm output to 10 MW between October 9, 2007 and July 3, 2008. Tawhiri sought alleged damages for lost production in the amount of $13 million, plus unspecified damages for lost production tax credits, overhead losses, and consultant and legal fees. HELCO responded to Tawhiri’s arbitration request on July 2, 2009, stating, among other points, that the curtailment was justified because Tawhiri failed to meet the low voltage ride-through requirements of the RAC and improperly disconnected from the grid on October 9, 2007. Under the dispute resolution provisions of the RAC, a decision in the arbitration could be rendered by or before mid-2010. In addition to the curtailment issue, HELCO and Tawhiri have other disputes relating to costs of

interconnection facilities, reconciliation of transmission line losses, and transfer of land and title to the switching station. These other disputes have not yet proceeded to arbitration.

Collective bargaining agreements. As of June 30, 2009, approximately 56% 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 six months ended June 30, 2009 and 2008, HECO and its subsidiaries paid interest amounting to $21 million and $24 million, respectively.

For the six months ended June 30, 2009 and 2008, HECO and its subsidiaries paid income taxes amounting to $12 million and $80 million, respectively. The significant change was due primarily to the differences in the taxes refundable or due with the extensions for tax years 2008 and 2007 and in the estimated tax payments due for the first half of 2009 and the first half of 2008. 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. This larger taxable income also resulted in disproportionately higher estimated tax payments for the first two quarters of 2008 versus the first two quarters 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 $7.7 million and $4.0 million for the six months ended June 30, 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 • Fair value of financial instruments

Fair value estimates are based on the price that would be received to sell an asset, or paid upon the transfer of a liability, in an orderly transaction between market participants at the measurement date. The fair value estimates are generally determined based on assumptions that market participants would use in pricing the asset or liability and are based on market data obtained from independent sources. However, in certain cases, the electric utilities use their own assumptions about market participant assumptions based on the best information available in the circumstances. These valuations are estimates at a specific point in time, based on relevant market information, information about the financial instrument and judgments regarding future expected loss experience, economic conditions, risk characteristics of various financial instruments and other factors. These

estimates do not reflect any premium or discount that could result if the electric utilities were to sell their entire holdings of a particular financial instrument at one time. Because no market exists for a portion of the electric utilities’ financial instruments, fair value estimates cannot be determined with precision. Changes in the underlying assumptions used, including discount rates and estimates of future cash flows, could significantly affect the estimates. Fair value estimates are provided for certain financial instruments without attempting to estimate the value of anticipated future business and the value of assets and liabilities that are not considered financial instruments. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates and have not been considered.

The electric utilities used the following methods and assumptions to estimate the fair value of each applicable class of financial instruments for which it is practicable to estimate that value:

Cash and equivalents and short-term borrowings

The carrying amount approximated fair value because of the short maturity of these instruments.

Long-term debt

Fair value was obtained from a third-party financial services provider based on the current rates offered for debt of the same or similar remaining maturities.

Off-balance sheet financial instruments

Fair value of HECO-obligated preferred securities of trust subsidiaries was based on quoted market prices.

The estimated fair values of the financial instruments held or issued by the electric utilities were as follows:


December 31	June 30, 2009				December 31, 2008
(in thousands)	Carrying amount		Estimated fair value		Carrying amount		Estimated fair value
Financial assets:
Cash and equivalents	$	3,676	$	3,676	$	6,901	$	6,901
Financial liabilities:
Short-term borrowings from affiliate and nonaffiliates		100,604		100,604		41,550		41,550
Long-term debt, net, including amounts due within one year		907,733		759,093		904,501		660,380
Off-balance sheet item:
HECO-obligated preferred securities of trust subsidiary		50,000		45,500		50,000		40,420

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


	Three months ended June 30						Six months ended June 30
(in thousands)	2009			2008			2009			2008
Operating income from regulated and nonregulated activities before income taxes (per HEI consolidated statements of income)	$	32,163		$	55,396		$	63,232		$	106,379
Deduct:
Income taxes on regulated activities		(8,727	)		(17,094	)		(17,271	)		(32,472	)
Revenues from nonregulated activities		(2,581	)		(1,474	)		(5,093	)		(2,869	)
Add:
Expenses from nonregulated activities		168			560			404			1,016

Operating income from regulated activities after income taxes (per HECO consolidated statements of income)	$	21,023		$	37,388		$	41,272		$	72,054

10 • Subsequent events

HECO and its subsidiaries have evaluated subsequent events through August 7, 2009 (12:01 a.m.), the date the financial statements were issued.

On July 30, 2009, the Department of Budget and Finance of the State of Hawaii closed the sale at par of special purpose revenue bonds (SPRBs) for the benefit of HECO and HELCO in the aggregate principal amount of $150 million, which bonds are uninsured, have a maturity of July 1, 2039 and a fixed coupon rate of 6.50%. Proceeds from the SPRBs were loaned to HECO ($90 million) and HELCO ($60 million), and used to reimburse HECO and HELCO for their previously incurred capital expenditures and, in turn, are expected to be used principally to repay their short-term borrowings.

Effective December 8, 2008, HECO entered into a 9-month revolving unsecured credit agreement establishing a line of credit facility of $75 million with a syndicate of four financial institutions (HECO $75 Million Facility). On August 4, 2009, the second business day following receipt of the proceeds of the Series 2009 SPRBs by HECO and HELCO, the HECO $75 Million Facility terminated in accordance with its terms.

On July 2, 2009, the PUC issued an interim D&O in HECO’s 2009 test year rate case granting an annual increase of approximately $61.1 million, or 4.7%, which was implemented on August 3, 2009.

11 • 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 June 30, 2009


(in thousands)	HECO		HELCO	MECO	RHI	UBC	Reclassifications and eliminations	HECO consolidated
Operating revenues	$	300,395	79,674	67,767	—	—	—	$	447,836

Operating expenses
Fuel oil		86,808	15,762	29,315	—	—	—		131,885
Purchased power		84,329	26,731	4,129	—	—	—		115,189
Other operation		44,644	8,718	9,819	—	—	—		63,181
Maintenance		17,448	5,696	6,287	—	—	—		29,431
Depreciation		20,798	8,250	7,377	—	—	—		36,425
Taxes, other than income taxes		28,273	7,410	6,292	—	—	—		41,975
Income taxes		5,690	2,290	747	—	—	—		8,727

		287,990	74,857	63,966	—	—	—		426,813

Operating income		12,405	4,817	3,801	—	—	—		21,023

Other income
Allowance for equity funds used during construction		3,176	767	177	—	—	—		4,120
Equity in earnings of subsidiaries		5,249