HAWAIIAN ELECTRIC INDUSTRIES INC (Form: 10-Q, Received: 11/05/2008 06:02:42)

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2008

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


Exact Name of Registrant as Specified in Its Charter	Commission File Number	I.R.S. Employer Identification No.
HAWAIIAN ELECTRIC INDUSTRIES, INC.	1-8503	99-0208097
and Principal Subsidiary
HAWAIIAN ELECTRIC COMPANY, INC.	1-4955	99-0040500

State of Hawaii

(State or other jurisdiction of incorporation or organization)

900 Richards Street, Honolulu, Hawaii 96813

(Address of principal executive offices and zip code)

Hawaiian Electric Industries, Inc. — (808) 543-5662

Hawaiian Electric Company, Inc. — (808) 543-7771

(Registrant’s telephone number, including area code)

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc. (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

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

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

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

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

APPLICABLE ONLY TO CORPORATE ISSUERS:

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


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

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended September 30, 2008

INDEX


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

	PART I. FINANCIAL INFORMATION

	Item 1.	Financial Statements

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

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

	PART II. OTHER INFORMATION

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

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended September 30, 2008

GLOSSARY OF TERMS


Terms		Definitions
AFUDC		Allowance for funds used during construction

AOCI		Accumulated other comprehensive income

ASB		American Savings Bank, F.S.B., a wholly-owned subsidiary of HEI Diversified, Inc. and parent company of American Savings Investment Services Corp. (and its subsidiary, Bishop Insurance Agency of Hawaii, Inc.). Former subsidiaries include ASB Service Corporation (dissolved in January 2004), ASB Realty Corporation (dissolved in May 2005) and AdCommunications, Inc. (dissolved in May 2007).

CHP		Combined heat and power

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

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

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

D&O		Decision and order

DG		Distributed generation

DOD		Department of Defense — federal

DOH		Department of Health of the State of Hawaii

DRIP		HEI Dividend Reinvestment and Stock Purchase Plan

DSM		Demand-side management

ECAC		Energy cost adjustment clauses

EITF		Emerging Issues Task Force

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

EPA		Environmental Protection Agency — federal

Exchange Act		Securities Exchange Act of 1934

FASB		Financial Accounting Standards Board

federal		U.S. Government

FHLB		Federal Home Loan Bank

FIN		Financial Accounting Standards Board Interpretation No.

GAAP		U.S. generally accepted accounting principles
HCEI		Hawaii Clean Energy Initiative

HECO		Hawaiian Electric Company, Inc., an electric utility subsidiary of Hawaiian Electric Industries, Inc. and parent company of Hawaii Electric Light Company, Inc., Maui Electric Company, Limited, Renewable Hawaii, Inc., Uluwehiokama Biofuels Corp. and HECO Capital Trust III. Former subsidiaries include HECO Capital Trust I (dissolved and terminated in 2004)* and HECO Capital Trust II (dissolved and terminated in 2004). (unconsolidated subsidiaries as of January 1, 2004).

GLOSSARY OF TERMS, continued


Terms		Definitions

HEI		Hawaiian Electric Industries, Inc., direct parent company of Hawaiian Electric Company, Inc., HEI Diversified, Inc., Pacific Energy Conservation Services, Inc., HEI Properties, Inc., HEI Investments, Inc., Hawaiian Electric Industries Capital Trust II, Hawaiian Electric Industries Capital Trust III and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.). Former subsidiaries (other than those sold or dissolved prior to 2004) are listed under Company.

HEIDI		HEI Diversified, Inc., a wholly owned subsidiary of Hawaiian Electric Industries, Inc. and the parent company of American Savings Bank, F.S.B.

HEIII		HEI Investments, Inc. (formerly HEI Investment Corp.), a wholly owned subsidiary of Hawaiian Electric Industries, Inc.

HELCO		Hawaii Electric Light Company, Inc., an electric utility subsidiary of Hawaiian Electric Company, Inc.

HPOWER		City and County of Honolulu with respect to a power purchase agreement for a refuse-fired plant

IPP		Independent power producer

IRP		Integrated resource plan

Kalaeloa		Kalaeloa Partners, L.P.

kV		Kilovolt

kw		Kilowatts

KWH		Kilowatthour

MECO		Maui Electric Company, Limited, an electric utility subsidiary of Hawaiian Electric Company, Inc.

MW		Megawatt/s (as applicable)

NII		Net interest income

NPV		Net portfolio value

NQSO		Nonqualified stock option

OPEB		Postretirement benefits other than pensions

OTS		Office of Thrift Supervision, Department of Treasury

PPA		Power purchase agreement

PRPs		Potentially responsible parties

PUC		Public Utilities Commission of the State of Hawaii

RHI		Renewable Hawaii, Inc., a wholly owned subsidiary of Hawaiian Electric Company, Inc.

ROACE		Return on average common equity

ROR		Return on average rate base

RPS		Renewable portfolio standards

SAR		Stock appreciation right

SEC		Securities and Exchange Commission

See		Means the referenced material is incorporated by reference

SFAS		Statement of Financial Accounting Standards

SOIP		1987 Stock Option and Incentive Plan, as amended

SPRBs		Special Purpose Revenue Bonds

TOOTS		The Old Oahu Tug Service, a wholly owned subsidiary of Hawaiian Electric Industries, Inc.

UBC		Uluwehiokama Biofuels Corp., a newly formed, non-regulated subsidiary of Hawaiian Electric Company, Inc.

VIE		Variable interest entity

iii

FORWARD-LOOKING STATEMENTS

This report and other presentations made by Hawaiian Electric Industries, Inc. (HEI) and Hawaiian Electric Company, Inc. (HECO) and their subsidiaries contain “forward-looking statements,” which include statements that are predictive in nature, depend upon or refer to future events or conditions, and usually include words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “predicts,” “estimates” or similar expressions. In addition, any statements concerning future financial performance, ongoing business strategies or prospects and possible future actions are also forward-looking statements. Forward-looking statements are based on current expectations and projections about future events and are subject to risks, uncertainties and the accuracy of assumptions concerning HEI and its subsidiaries (collectively, the Company), the performance of the industries in which they do business and economic and market factors, among other things. These forward-looking statements are not guarantees of future performance.

Risks, uncertainties and other important factors that could cause actual results to differ materially from those in forward-looking statements and from historical results include, but are not limited to, the following:

•

the effects of international, national and local economic conditions, including the state of the Hawaii tourist and construction industries, the strength or weakness of the Hawaii and continental U.S. real estate markets (including the fair value and/or the actual performance of collateral underlying loans and mortgage-related securities held by American Savings Bank, F.S.B. (ASB)), decisions concerning the extent of the presence of the federal government and military in Hawaii, and the implications and potential impacts of the current capital market conditions and the Emergency Economic Stabilization Act of 2008 (President Bush administration’s plan for a $700 billion bailout of the financial industry);

•

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

•

global developments, including the effects of terrorist acts, the war on terrorism, continuing U.S. presence in Iraq and Afghanistan, potential conflict or crisis with North Korea and in the Middle East, Iran’s nuclear activities and potential avian flu pandemic;

•

the timing and extent of changes in interest rates and the shape of the yield curve;

•

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

•

the risks inherent in changes in the value of and market for securities available for sale and in the value of pension and other retirement plan assets;

•

changes in assumptions used to calculate retirement benefits costs and changes in funding requirements;

•

increasing competition in the electric utility and banking industries (e.g., increased self-generation of electricity may have an adverse impact on HECO’s revenues and increased price competition for deposits, or an outflow of deposits to alternative investments, may have an adverse impact on ASB’s cost of funds);

•

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

•

capacity and supply constraints or difficulties, especially if generating units (utility-owned or independent power producer (IPP)-owned) fail or measures such as demand-side management (DSM), distributed generation (DG), combined heat and power (CHP) or other firm capacity supply-side resources fall short of achieving their forecasted benefits or are otherwise insufficient to reduce or meet peak demand;

•

increased risk to generation reliability as generation peak reserve margins on Oahu continue to be strained;

•

fuel oil price changes, performance by suppliers of their fuel oil delivery obligations and the continued availability to the electric utilities of their energy cost adjustment clauses (ECACs);

•

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

•

the ability of IPPs to deliver the firm capacity anticipated in their power purchase agreements (PPAs);

•

the ability of the electric utilities to negotiate, periodically, favorable fuel supply and collective bargaining agreements;

•

new technological developments that could affect the operations and prospects of HEI and its subsidiaries (including HECO and its subsidiaries and ASB and its subsidiaries) or their competitors;

•

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

•

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

•

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

•

the effects of changes in accounting principles applicable to HEI, HECO, ASB and their subsidiaries, including the adoption of international accounting standards or new accounting principles, continued regulatory accounting under Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” and the possible effects of applying Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46R, “Consolidation of Variable Interest Entities,” and Emerging Issues Task Force (EITF) Issue No. 01-8, “Determining Whether an Arrangement Contains a Lease,” to PPAs with independent power producers;

•

the effects of changes by securities rating agencies in their ratings of the securities of HEI and HECO and the results of financing efforts;

•

faster than expected loan prepayments that can cause an acceleration of the amortization of premiums on loans and investments and the impairment of mortgage servicing assets of ASB;

•

changes in ASB’s loan portfolio credit profile and asset quality which may increase or decrease the required level of allowance for loan losses;

•

changes in ASB’s deposit cost or mix which may have an adverse impact on ASB’s cost of funds;

•

the final outcome of tax positions taken by HEI, HECO, ASB and their subsidiaries;

•

the risks of suffering losses and incurring liabilities that are uninsured or having insurance coverages with a troubled or failing insurer (e.g., American International Group Inc.); and

•

other risks or uncertainties described elsewhere in this report and in other reports (e.g., “Item 1A. Risk Factors” in the Company’s Annual Report on Form 10-K) previously and subsequently filed by HEI and/or HECO with the Securities and Exchange Commission (SEC).

Forward-looking statements speak only as of the date of the report, presentation or filing in which they are made. Except to the extent required by the federal securities laws, HEI, HECO, ASB and their subsidiaries undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)


(in thousands, except per share amounts and ratio of earnings to fixed charges)	Three months ended September 30						Nine months ended September 30
	2008			2007			2008			2007
Revenues
Electric utility	$	827,788		$	567,615		$	2,139,798		$	1,508,005
Bank		87,675			105,507			279,469			317,493
Other		(32	)		339			(164	)		2,749

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Including interest on ASB deposits								1.76			1.35

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

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)


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

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

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

		7,886,034			8,984,196

Minority interests
Preferred stock of subsidiaries - not subject to mandatory redemption		34,293			34,293

Stockholders’ equity
Preferred stock, no par value, authorized 10,000,000 shares; issued: none		—			—
Common stock, no par value, authorized 200,000,000 shares; issued and outstanding: 85,080,748 shares and 83,431,513 shares		1,111,034			1,072,101
Retained earnings		223,294			225,168
Accumulated other comprehensive loss, net of tax benefits		(13,728	)		(21,842	)

		1,320,600			1,275,427

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

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

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Changes in Stockholders’ Equity (unaudited)


(in thousands, except per share amounts)	Common stock			Retained earnings			Accumulated other comprehensive loss			Total
(in thousands, except per share amounts)	Shares	Amount		Retained earnings			Accumulated other comprehensive loss			Total
Balance, December 31, 2007	83,432	$	1,072,101	$	225,168		$	(21,842	)	$	1,275,427
Comprehensive income:
Net income	—		—		76,384			—			76,384
Net unrealized losses on securities:
Net unrealized losses on securities arising during the period, net of tax benefits of $1,842	—		—		—			(2,788	)		(2,788	)
Less: reclassification adjustment for net realized losses included in net income, net of tax benefits of $6,915	—		—		—			10,472			10,472
Retirement benefit plans:
Amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes of $2,775	—		—		—			4,358			4,358
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $2,501	—		—		—			(3,928	)		(3,928	)

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

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

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

Balance, December 31, 2006	81,461	$	1,028,101	$	242,667		$	(175,528	)	$	1,095,240
Comprehensive income:
Net income	—		—		44,194			—			44,194
Net unrealized gains on securities arising during the period, net of taxes of $6,748	—		—		—			10,219			10,219
Retirement benefit plans - amortization of net loss, prior service cost and transition obligation included in net periodic benefit cost, net of taxes of $3,825	—		—		—			5,993			5,993

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

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

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

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

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)


	Nine months ended September 30
(in thousands)	2008			2007
Cash flows from operating activities
Net income	$	76,384		$	44,194
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment		113,423			111,007
Other amortization		3,927			9,275
Provision for loan losses		4,034			3,900
Writedown of utility plant		—			11,701
Deferred income taxes		12,186			(18,068	)
Allowance for equity funds used during construction		(6,432	)		(3,770	)
Excess tax benefits from share-based payment arrangements		(572	)		(346	)
Loans receivable originated and purchased, held for sale		(159,327	)		(31,699	)
Proceeds from sale of loans receivable, held for sale		157,293			31,904
Net loss on sale of investment and mortgage-related securities		17,388			—
Changes in assets and liabilities
Increase in accounts receivable and unbilled revenues, net		(76,034	)		(28,147	)
Increase in fuel oil stock		(79,693	)		(35,904	)
Increase in accounts payable		54,460			54,232
Change in prepaid and accrued income taxes and utility revenue taxes		(29,640	)		18,744
Changes in other assets and liabilities		(13,278	)		2,955

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

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

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

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

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

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

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

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

Hawaiian Electric Industries, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) Basis of presentation

The accompanying unaudited consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles (GAAP) for interim financial information, the instructions to SEC Form 10-Q and Article 10 of Regulation S–X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenues and expenses for the period. Actual results could differ significantly from those estimates. The accompanying unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and the notes thereto included in HEI’s Form 10-K for the year ended December 31, 2007 and the unaudited consolidated financial statements and the notes thereto in HEI’s Quarterly Reports on SEC Form 10-Q for the quarters ended March 31, 2008 and June 30, 2008.

In the opinion of HEI’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to present fairly the Company’s financial position as of September 30, 2008 and December 31, 2007 and the results of its operations for the three and nine months ended September 30, 2008 and 2007 and its cash flows for the nine months ended September 30, 2008 and 2007. All such adjustments are of a normal recurring nature, unless otherwise disclosed in this Form 10-Q or other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year. When required, certain reclassifications are made to the prior period’s consolidated financial statements to conform to the current presentation.

(2) Segment financial information


(in thousands)	Electric Utility		Bank		Other			Total
Three months ended September 30, 2008
Revenues from external customers	$	827,731	$	87,675	$	25		$	915,431
Intersegment revenues (eliminations)		57		—		(57	)		—

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

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

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

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

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

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

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

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

Three months ended September 30, 2007
Revenues from external customers	$	567,570	$	105,507	$	384		$	673,461
Intersegment revenues (eliminations)		45		—		(45	)		—

Revenues		567,615		105,507		339			673,461

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

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

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

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

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

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

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

*	Income (loss) before income taxes.

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

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

(3) Electric utility subsidiary

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

(4) Bank subsidiary

Selected financial information

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

Consolidated Statements of Income Data (unaudited)


	Three months ended September 30				Nine months ended September 30
(in thousands)	2008		2007		2008			2007
Interest and dividend income
Interest and fees on loans	$	61,100	$	61,817	$	186,312		$	182,191
Interest and dividends on investment and mortgage-related securities		9,898		26,497		57,078			85,090

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

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

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

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

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

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

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

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

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

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

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

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

Consolidated Balance Sheets Data (unaudited)


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

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

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

		4,984,244			6,266,729

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

		530,544			594,764

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

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

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

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

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

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

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

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

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

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

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

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


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

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

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

Assets Measured at Fair Value on a Recurring Basis

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

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


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

Assets Measured at Fair Value on a Nonrecurring Basis

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

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


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

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

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

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

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

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

(5) Retirement benefits

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

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

The components of net periodic benefit cost were as follows:


	Three months ended September 30												Nine months ended September 30
	Pension benefits						Other benefits						Pension benefits						Other benefits
(in thousands)	2008 ⁽¹⁾			2007			2008			2007			2008 ⁽¹⁾			2007			2008			2007
Service cost	$	7,255		$	7,746		$	1,215		$	1,166		$	21,100		$	23,250		$	3,562		$	3,606
Interest cost		14,987			14,494			2,690			2,598			44,778			43,358			8,318			8,232
Expected return on plan assets		(18,335	)		(17,091	)		(2,745	)		(2,619	)		(54,836	)		(51,291	)		(8,227	)		(7,321	)
Amortization of unrecognized transition obligation		—			—			785			785			2			2			2,354			2,354
Amortization of prior service cost (gain)		(116	)		(50	)		3			3			(305	)		(148	)		10			10
Recognized actuarial loss		1,692			2,796			—			—			5,073			8,486			—			—

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

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

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

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

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

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

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

(6) Share-based compensation

Under the 1987 Stock Option and Incentive Plan, as amended (SOIP), HEI may issue an aggregate of 9.3 million shares of common stock (4.5 million shares available for issuance under outstanding and future grants and awards as of September 30, 2008) to officers and key employees as incentive stock options, nonqualified stock options (NQSOs), restricted stock, stock appreciation rights (SARs), stock payments or dividend equivalents. HEI has issued new shares for NQSOs, restricted stock (nonvested stock), SARs and dividend equivalents under the SOIP. All information presented has been adjusted for the 2-for-1 stock split in June 2004.

For the NQSOs and SARs, the exercise price of each NQSO or SAR generally equaled the fair market value of HEI’s stock on or near the date of grant. NQSOs, SARs and related dividend equivalents issued in the form of stock awarded prior to and through 2004 generally become exercisable in installments of 25% each year for four years, and expire if not exercised ten years from the date of the grant. The 2005 SARs awards, which have a ten year exercise life, generally become exercisable at the end of four years (i.e., cliff vesting) with the related dividend equivalents issued in the form of stock on an annual basis. Accelerated vesting is provided in the event of a change-in-control or upon retirement. NQSOs and SARs compensation expense has been recognized in accordance with the fair value-based measurement method of accounting. The estimated fair value of each NQSO and SAR grant was calculated on the date of grant using a Binomial Option Pricing Model.

Restricted stock grants generally become unrestricted three to five years after the date of grant and restricted stock compensation expense has been recognized in accordance with the fair value-based measurement method of accounting. Dividends on restricted stock are paid quarterly in cash.

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


	Three months ended September 30		Nine months ended September 30
($ in millions)	2008	2007	2008	2007
Share-based compensation expense ¹	0.3	0.4	0.5	1.1
Income tax benefit	0.1	0.1	0.1	0.3

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

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


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

	$14.74 – 21.68	377,500	3.3	$19.72

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

NQSO activity and statistics are summarized as follows:


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

¹	Intrinsic value is the amount by which the fair market value of the underlying stock and the related dividend equivalents exceeds the exercise price of the option.

As of September 30, 2008, all NQSOs were vested.

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


September 30, 2008		Outstanding			Exercisable
Year of grant	Range of exercise prices	Number of shares underlying SARs	Weighted- average remaining contractual life	Weighted- average exercise price	Number of shares underlying SARs	Weighted- average remaining contractual life	Weighted- average exercise price
2004	$26.02	295,000	3.1	$26.02	295,000	3.1	$26.02
2005	26.18	502,000	4.2	26.18	218,000	1.1	26.18

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

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

SARs activity and statistics are summarized as follows:


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

¹	Intrinsic value is the amount by which the fair market value of the underlying stock and the related dividend equivalents exceeds the exercise price of the right.

As of September 30, 2008, there was $0.1 million of total unrecognized compensation cost related to SARs and that cost is expected to be recognized over a weighted average period of 0.6 years.

Section 409A modification. As a result of the changes enacted in Section 409A of the Internal Revenue Code of 1986, as amended (Section 409A), for the nine months ended September 30, 2008 and 2007 a total of 6,125 and 45,652 dividend equivalent shares for NQSO and SAR grants were distributed to SOIP participants, respectively. Section 409A, which amended the rules on deferred compensation, required the Company to change the way certain affected dividend equivalents are paid in order to avoid significant adverse tax consequences to the SOIP participants. Generally, dividend equivalents subject to Section 409A will be paid within 2 ¹ / 2 months after the end of the calendar year. Upon retirement, an SOIP participant may elect to take distributions of dividend equivalents subject to Section 409A at the time of retirement or at the end of the calendar year.

Restricted stock. As of September 30, 2008 and December 31, 2007, restricted stock shares outstanding totaled 161,200 and 146,000, respectively, with a weighted-average grant date fair value of $25.51 and $25.82, respectively. The grant date fair value of a grant of a restricted stock share was the closing or average price of HEI common stock on the date of grant.

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


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

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

As of September 30, 2008, there was $2.1 million of total unrecognized compensation cost related to nonvested restricted stock. The cost is expected to be recognized over a weighted-average period of 2.8 years.

(7) Commitments and contingencies

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

(8) Cash flows

Supplemental disclosures of cash flow information. For the nine months ended September 30, 2008 and 2007, the Company paid interest (net of amounts capitalized and including bank interest) to non-affiliates amounting to $137 million and $167 million, respectively.

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

Supplemental disclosures of noncash activities. Noncash increases in common stock for director and officer compensatory plans of the Company were $1.5 million and $2.0 million for the nine months ended September 30, 2008 and 2007, respectively.

Under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP), common stock dividends reinvested by shareholders in HEI common stock in noncash transactions amounted to $16 million and $15 million for the nine month periods ended September 30, 2008 and 2007, respectively. From March 23,

2004 to March 5, 2007, HEI satisfied the requirements of the HEI DRIP and the Hawaiian Electric Industries Retirement Savings Plan by acquiring for cash its common shares through open market purchases rather than the issuance of additional shares. Since March 6, 2007, HEI has been satisfying those requirements by the issuance of additional shares.

(9) Recent accounting pronouncements and interpretations

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

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

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)


	Three months ended September 30						Nine months ended September 30
(in thousands, except for ratio of earnings to fixed charges)	2008			2007			2008			2007
Operating revenues	$	826,124		$	561,720		$	2,135,265		$	1,499,766

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

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

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

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

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

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

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

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

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

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

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

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

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)


(in thousands, except par value)	September 30, 2008			December 31, 2007
Assets
Utility plant, at cost
Land	$	37,790		$	38,161
Plant and equipment		4,223,353			4,131,226
Less accumulated depreciation		(1,715,765	)		(1,647,113	)
Plant acquisition adjustment, net		6			41
Construction in progress		214,587			151,179

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

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

Total current assets		595,410			407,598

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

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

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

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

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

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

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

Total current liabilities		572,585			428,841

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

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

Contributions in aid of construction		304,977			299,737

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

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Changes in Common Stock Equity (unaudited)


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

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

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

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

Balance, December 31, 2006	12,806	$	85,387	$	299,214	$	700,252		$	(126,650	)	$	958,203
Comprehensive income:
Net income	—		—		—		23,978			—			23,978
Retirement benefit plans - amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes of $3,410	—		—		—		—			5,355			5,355

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

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

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

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)


Nine months ended September 30	2008			2007
	(in thousands)
Cash flows from operating activities
Income before preferred stock dividends of HECO	$	78,759		$	24,788
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities
Depreciation of property, plant and equipment		106,254			102,812
Other amortization		6,426			6,450
Writedown of utility plant		—			11,701
Deferred income taxes		6,588			(17,925	)
Tax credits, net		1,503			1,944
Allowance for equity funds used during construction		(6,432	)		(3,770	)
Changes in assets and liabilities
Increase in accounts receivable		(59,551	)		(22,073	)
Increase in accrued unbilled revenues		(23,394	)		(7,996	)
Increase in fuel oil stock		(79,693	)		(35,904	)
Increase in materials and supplies		(3,435	)		(4,420	)
Increase in regulatory assets		(28	)		(2,129	)
Increase in accounts payable		46,324			44,547
Change in prepaid and accrued income and utility revenue taxes		(7,969	)		12,039
Changes in other assets and liabilities		(5,386	)		17,515

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

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

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

Cash flows from financing activities
Common stock dividends		(14,088	)		(13,507	)
Preferred stock dividends		(810	)		(810	)
Proceeds from issuance of long-term debt		18,707			230,421
Repayment of long-term debt		—			(126,000	)
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		112,204			(83,482	)
Decrease in cash overdraft		(8,582	)		(12,076	)

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

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

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

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

Hawaiian Electric Company, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) Basis of presentation

The accompanying unaudited consolidated financial statements have been prepared in conformity with GAAP for interim financial information, the instructions to SEC Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenues and expenses for the period. Actual results could differ significantly from those estimates. The accompanying unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and the notes thereto incorporated by reference in HECO’s Form 10-K for the year ended December 31, 2007 and the unaudited consolidated financial statements and the notes thereto in HECO’s Quarterly Reports on SEC Form 10-Q for the quarters ended March 31, 2008 and June 30, 2008.

In the opinion of HECO’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to present fairly the financial position of HECO and its subsidiaries as of September 30, 2008 and December 31, 2007 and the results of their operations for the three and nine months ended September 30, 2008 and 2007 and their cash flows for the nine months ended September 30, 2008 and 2007. All such adjustments are of a normal recurring nature, unless otherwise disclosed in this Form 10-Q or other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year. When required, certain reclassifications are made to the prior period’s consolidated financial statements to conform to the current presentation.

(2) Unconsolidated variable interest entities

HECO Capital Trust III. HECO Capital Trust III (Trust III) was created and exists for the exclusive purposes of (i) issuing in March 2004 2,000,000 6.50% Cumulative Quarterly Income Preferred Securities, Series 2004 (2004 Trust Preferred Securities) ($50 million aggregate liquidation preference) to the public and trust common securities ($1.5 million aggregate liquidation preference) to HECO, (ii) investing the proceeds of these trust securities in 2004 Debentures issued by HECO in the principal amount of $31.5 million and issued by each of Hawaii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (MECO) in the respective principal amounts of $10 million, (iii) making distributions on the trust securities and (iv) engaging in only those other activities necessary or incidental thereto. The 2004 Trust Preferred Securities are mandatorily redeemable at the maturity of the underlying debt on March 18, 2034, which maturity may be extended to no later than March 18, 2053; and are redeemable at the issuer’s option without premium beginning on March 18, 2009. The 2004 Debentures, together with the obligations of HECO, HELCO and MECO under an expense agreement and HECO’s obligations under its trust guarantee and its guarantee of the obligations of HELCO and MECO under their respective debentures, are the sole assets of Trust III. Trust III has at all times been an unconsolidated subsidiary of HECO. Since HECO, as the common security holder, does not absorb the majority of the variability of Trust III, HECO is not the primary beneficiary and does not consolidate Trust III in accordance with FIN 46R, “Consolidation of Variable Interest Entities.” Trust III’s balance sheets as of September 30, 2008 and December 31, 2007 each consisted of $51.5 million of 2004 Debentures; $50.0 million of 2004 Trust Preferred Securities; and $1.5 million of trust common securities. Trust III’s income statements for nine months ended September 30, 2008 and 2007 each consisted of $2.5 million of interest income received from the 2004 Debentures; $2.4 million of distributions to holders of the Trust Preferred Securities; and $0.1 million of common dividends on the trust common securities to HECO. So long as the 2004 Trust Preferred Securities are outstanding, HECO is not entitled to receive any funds from Trust III other than pro rata distributions, subject to certain subordination provisions, on the trust common securities. In the event of a default by HECO in the performance of its obligations under the 2004 Debentures or under its Guarantees, or in the event HECO, HELCO or MECO elect to defer payment of interest on any of their

respective 2004 Debentures, then HECO will be subject to a number of restrictions, including a prohibition on the payment of dividends on its common stock.

Purchase power agreements. As of September 30, 2008, HECO and its subsidiaries had six PPAs for a total of 540 megawatts (MW) of firm capacity, and other PPAs with smaller IPPs and Schedule Q providers (i.e., customers with cogeneration and/or small power production facilities with a capacity of 100 KWHs or less who buy power from or sell power to the utilities) that supplied as-available energy. Approximately 91% of the 540 MW of firm capacity is under PPAs, entered into before December 31, 2003, with AES Hawaii, Inc. (AES Hawaii), Kalaeloa Partners, L.P. (Kalaeloa), Hamakua Energy Partners, L.P. (HEP) and HPOWER. Purchases from all IPPs for the nine months ended September 30, 2008 totaled $530 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $106 million, $214 million, $69 million and $46 million, respectively. The primary business activities of these IPPs are the generation and sale of power to HECO and its subsidiaries (and municipal waste disposal in the case of HPOWER). Current financial information about the size, including total assets and revenues, for many of these IPPs is not publicly available.

Under FIN 46R, an enterprise with an interest in a variable interest entity (VIE) or potential VIE created before December 31, 2003 (and not thereafter materially modified) is not required to apply FIN 46R to that entity if the enterprise is unable to obtain, after making an exhaustive effort, the necessary information.

HECO reviewed its significant PPAs and determined in 2004 that the IPPs at that time had no contractual obligation to provide such information. In March 2004, HECO and its subsidiaries sent letters to all of their IPPs, except the Schedule Q providers, requesting the information that they need to determine the applicability of FIN 46R to the respective IPP, and subsequently contacted most of the IPPs to explain and repeat its request for information. (HECO and its subsidiaries excluded their Schedule Q providers from the scope of FIN 46R because their variable interest in the provider would not be significant to the utilities and they did not participate significantly in the design of the provider.) Some of the IPPs provided sufficient information for HECO to determine that the IPP was not a VIE, or was either a “business” or “governmental organization” (HPOWER) as defined under FIN 46R, and thus excluded from the scope of FIN 46R. Other IPPs, including the three largest, declined to provide the information necessary for HECO to determine the applicability of FIN 46R, and HECO was unable to apply FIN 46R to these IPPs.

As required under FIN 46R, since 2004 HECO has continued its efforts to obtain from the IPPs the information necessary to make the determinations required under FIN 46R. In January 2005, 2006, 2007 and 2008, HECO and its subsidiaries sent letters to the IPPs that were not excluded from the scope of FIN 46R, requesting the information required to determine the applicability of FIN 46R to the respective IPP. All of these IPPs declined to provide necessary information, except that Kalaeloa provided the information pursuant to the amendments to the PPA (see below) and an entity owning a wind farm provided information as required under the PPA. Management has concluded that the consolidation of two entities owning wind farms was not required as MECO and HELCO do not have variable interests in the entities because the PPAs do not require them to absorb any variability of the entities.

If the requested information is ultimately received from the other IPPs, a possible outcome of future analysis is the consolidation of one or more of such IPPs in HECO’s consolidated financial statements. The consolidation of any significant IPP could have a material effect on HECO’s consolidated financial statements, including the recognition of a significant amount of assets and liabilities, and, if such a consolidated IPP were operating at a loss and had insufficient equity, the potential recognition of such losses. If HECO and its subsidiaries determine they are required to consolidate the financial statements of such an IPP and the consolidation has a material effect, HECO and its subsidiaries would retrospectively apply FIN 46R in accordance with SFAS No. 154, “Accounting Changes and Error Corrections.”

Kalaeloa Partners, L.P. In October 1988, HECO entered into a PPA with Kalaeloa, subsequently approved by the PUC, which provided that HECO would purchase 180 MW of firm capacity for a period of 25 years beginning in May 1991. In October 2004, HECO and Kalaeloa entered into amendments to the PPA, subsequently approved by the PUC, which together effectively increased the firm capacity from 180 MW to 208 MW. The energy payments that HECO makes to Kalaeloa include: 1) a fuel component, with a fuel price adjustment based on the cost of low

sulfur fuel oil, 2) a fuel additives cost component, and 3) a non-fuel component, with an adjustment based on changes in the Gross National Product Implicit Price Deflator. The capacity payments that HECO makes to Kalaeloa are fixed in accordance with the PPA. Kalaeloa also has a steam delivery contract with another customer, the term of which coincides with the PPA. The cogeneration facility has been certified by the Federal Energy Regulatory Commission as a Qualifying Facility under the Public Utility Regulatory Policies Act of 1978.

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

(3) Revenue taxes

HECO and its subsidiaries’ operating revenues include amounts for various revenue taxes. Revenue taxes are generally recorded as an expense in the period the related revenues are recognized. HECO and its subsidiaries’ payments to the taxing authorities are based on the prior year’s revenues. For the nine months ended September 30, 2008 and 2007, HECO and its subsidiaries included approximately $187 million and $134 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

(4) Retirement benefits

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

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

The components of net periodic benefit cost were as follows:


	Three months ended September 30												Nine months ended September 30
	Pension benefits						Other benefits						Pension benefits						Other benefits
(in thousands)	2008			2007			2008			2007			2008			2007			2008			2007
Service cost	$	6,863		$	6,418		$	1,179		$	1,137		$	20,039		$	19,109		$	3,464		$	3,516
Interest cost		13,528			12,951			2,617			2,515			40,446			38,637			8,081			7,998
Expected return on plan assets		(16,333	)		(15,311	)		(2,698	)		(2,580	)		(48,861	)		(45,789	)		(8,090	)		(7,201	)
Amortization of unrecognized transition obligation		—			—			783			783			—			1			2,348			2,348
Amortization of prior service gain		(191	)		(191	)		—			—			(572	)		(572	)		—			—
Recognized actuarial loss		1,646			2,625			—			—			4,935			7,861			—			—

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

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

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

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

The pension tracking mechanisms generally require the electric utilities to fund only the minimum level required under the law until the existing pension assets are reduced to zero, at which time the electric utilities would make contributions to the pension trust in the amount of the actuarially calculated net periodic pension costs, except when limited by the ERISA minimum contribution requirements or the maximum contribution limitation on deductible contributions imposed by the Internal Revenue code. The OPEB tracking mechanisms generally require the electric utilities to make contributions to the OPEB trust in the amount of the actuarially calculated net periodic benefit costs.

A pension funding study was filed in the HECO rate case in May 2007. The conclusions in the study were consistent with the funding practice proposed with the pension tracking mechanism.

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

Under HELCO’s interim order, a regulatory asset (representing HELCO’s $12.8 million prepaid pension asset as of December 31, 2006 prior to the adoption of SFAS No. 158) was allowed to be recovered (and is being amortized) over a period of five years and was allowed to be included in HELCO’s rate base, net of deferred income taxes. In the interim PUC decisions in HECO’s and MECO’s 2007 test year rate cases, their pension assets ($51 million and $1 million, respectively, as of December 31, 2007) were not included in their rate bases and amortization of the pension assets was not included as part of the pension tracking mechanisms adopted in the proceedings on an interim basis. The issue of whether to amortize HECO’s prepaid pension asset, if allowed to be included in rate base by the PUC, has been deferred until HECO’s next rate case proceeding. HECO’s pension asset was not included in rate base, and amortization of the pension asset was not included in revenue requirements, in HECO’s rate increase application based on a 2009 test year.

(5) Commitments and contingencies

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Interim increases. On April 4, 2007, the PUC issued an interim D&O in HELCO’s 2006 test year rate case granting a general rate increase on the island of Hawaii of 7.58%, or $25 million, which was implemented on April 5, 2007.

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

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

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

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

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

In the HELCO 2006 test year rate case, the filed testimony of the Consumer Advocate’s consultant concluded that HELCO’s ECAC provides a fair sharing of the risks of fuel cost changes between HELCO and its ratepayers in a manner that preserves the financial integrity of HELCO without the need for frequent rate filings. In April and December 2007, the PUC issued interim D&Os in the HELCO 2006 and MECO 2007 test year rate cases that reflected for purposes of the interim order the continuation of their ECACs, consistent with agreements reached between the Consumer Advocate and HELCO and MECO, respectively. The Consumer Advocate and MECO agreed that no further changes are required to MECO’s ECAC in order to comply with the requirements of Act 162.

In September 2007, HECO, the Consumer Advocate and the federal Department of Defense (DOD) agreed that the ECAC should continue in its present form for purposes of an interim rate increase in the HECO 2007 test year rate case and stated that they are continuing discussions with respect to the final design of the ECAC to be proposed for approval in the final D&O. In October 2007, the PUC issued an interim D&O, which reflected the continuation of HECO’s ECAC for purposes of the interim increase.

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

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

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

HECO’s Final Environmental Impact Statement for the Project was accepted by the Department of Planning & Permitting of the City and County of Honolulu in August 2006. In December 2006, HECO filed with the PUC an agreement with the Consumer Advocate in which HECO committed to use 100% biofuels in its new plant and to

take the steps necessary for HECO to reach that goal. In May 2007, the PUC issued a D&O approving the Project and the DOH issued the final air permit, which became effective at the end of June 2007. The D&O further stated that no part of the Project costs may be included in HECO’s rate base unless and until the Project is in fact installed, and is used and useful for public utility purposes. HECO’s 2009 test year rate case application, filed in July 2008, requests inclusion of the Project investment in rate base when the new unit is placed in service (expected to be at the end of July 2009). Construction on the Project began in May 2008.

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

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

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

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

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

In written testimony filed in 2005, a consultant for the Consumer Advocate contended that HECO should always have planned for a project using only the 46 kV system and recommended that HECO be required to expense the $12 million incurred prior to the denial of the permit in 2002, and the related allowance for funds used during construction (AFUDC) of $5 million at the time. HECO contested the consultant’s recommendation, emphasizing that the originally proposed 138 kV line would have been a more comprehensive and robust solution to the transmission concerns the project addresses. In October 2007, the PUC issued a final D&O approving HECO’s request to expend funds for the EOTP, but stating that the issue of recovery of the EOTP costs would be determined in a subsequent rate case, after the project is installed and in service.

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

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

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

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

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

HELCO generating units . In 1991, HELCO began planning to meet increased demand for electricity forecast for 1994. HELCO planned to install at its Keahole power plant two 20 MW combustion turbines (CT-4 and CT-5), followed by an 18 MW heat recovery steam generator (ST-7), at which time the units would be converted to a 56 MW (net) dual-train combined-cycle unit. There were a number of environmental and other permitting challenges to construction of the units, including several lawsuits, which resulted in significant delays. However, in 2003, all but one of the parties actively opposing the plant expansion project entered into a settlement agreement with HELCO and several Hawaii regulatory agencies intended in part to permit HELCO to complete CT-4 and CT-5. The settlement agreement required HELCO to undertake a number of actions, which have been completed or are ongoing. As a result of the final resolution of various proceedings due primarily to the Settlement Agreement, there are no pending lawsuits involving the project.

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

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

CT-4 and CT-5 costs incurred and allowed . HELCO’s capitalized costs for CT-4 and CT-5 and related supporting infrastructure amounted to $110 million. HELCO sought recovery of these costs as part of its 2006 test year rate case.

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

In April 2007, the PUC issued an interim D&O granting HELCO a 7.58% increase in rates, which D&O reflected the agreement to write-off $12 million of the CT-4 and CT-5 costs. However, the interim D&O does not commit the PUC to accept any of the amounts in the interim increase in its final D&O.

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

Environmental regulation. HEI and its subsidiaries are subject to environmental laws and regulations that regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic substances.

HECO, HELCO and MECO, like other utilities, periodically identify petroleum or other chemical releases into the environment associated with current operations and report and take action on these releases when and as required by applicable law and regulations. Except as otherwise disclosed herein, the Company believes the costs of responding to its subsidiaries’ releases identified to date will not have a material adverse effect, individually or in the aggregate, on the Company’s or consolidated HECO’s financial statements.

Additionally, current environmental laws may require HEI and its subsidiaries to investigate whether releases from historical operations may have contributed to environmental impacts, and, where appropriate, respond to

such releases, even if they were not inconsistent with law or standard industrial practices prevailing at the time when they occurred. Such releases may involve area-wide impacts contributed to by multiple potentially responsible parties.

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

Besides subsurface investigation, assessments and preliminary oil removal tasks that have been conducted by the Participating Parties, HECO and others investigated their ongoing operations in the Iwilei Unit in 2003 to evaluate whether their facilities were active sources of petroleum contamination in the area. HECO’s investigation concluded that its facilities were not then releasing petroleum. Routine maintenance and inspections of HECO facilities since then confirm that they are not currently releasing petroleum.

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

Through September 30, 2008, HECO has accrued a total of $3.3 million (including $0.4 million in the first quarter of 2008) for estimates of HECO’s share of costs for continuing investigative work, remedial activities and monitoring for the Iwilei unit. As of September 30, 2008, the remaining accrual (amounts expensed less amounts expended) for the Iwilei unit was $1.8 million. Because (1) the full scope of work remains to be determined, (2) the final cost allocation method among the PRPs has not yet been established and (3) management cannot estimate the costs to be incurred (if any) for the sites other than the Iwilei unit (such as its Honolulu power plant located in the Downtown unit of the Honolulu Harbor site), the cost estimate may be subject to significant change and additional material costs may be incurred.

Regional Haze Rule amendments . In June 2005, the EPA finalized amendments to the July 1999 Regional Haze Rule that require emission controls known as best available retrofit technology (BART) for industrial facilities emitting air pollutants that reduce visibility in National Parks by causing or contributing to regional haze. States were to adopt BART implementation plans and schedules in accordance with the amended regional haze rule by December 2007. After Hawaii adopts its plan, which it has not done to date, HECO, HELCO and MECO will evaluate the plan’s impacts, if any. If any of the utilities’ generating units are ultimately required to install post-combustion control technologies to meet BART emission limits, the resulting capital and operation and maintenance costs could be significant.

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

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

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

Clean Water Act . Section 316(b) of the federal Clean Water Act requires that the EPA ensure that existing power plant cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts. In 2004, the EPA issued a rule, which established design, construction and capacity standards for existing cooling water intake structures, such as those at HECO’s Kahe, Waiau and Honolulu generating stations, and required demonstrated compliance by March 2008. The rule provided a number of compliance options, some of which were far less costly than others. HECO had retained a consultant that was developing a cost effective compliance strategy.

In January 2007, the U.S. Circuit Court of Appeals for the Second Circuit issued a decision that remanded for further consideration and proceedings significant portions of the rule and found other portions to be impermissible. In July 2007, the EPA formally suspended the rule and provided guidance to federal and state permit writers that they should use their “best professional judgment” in determining permit conditions regarding cooling water intake requirements at existing power plants. HECO facilities are subject to permit renewal in mid-2009 and may be subject to new permit conditions to address cooling water intake requirements at that time. In April 2008, the U. S. Supreme Court agreed to review the Court of Appeal’s rejection of a cost-benefit test to determine compliance options. It is now expected that the Supreme Court will hear the case in December 2008, with a decision issued in the first half of 2009. If the Supreme Court affirms the Court of Appeal’s decision, the compliance options available to HECO are reduced. Due to the uncertainties regarding the Court of Appeal’s decision, management is unable to predict which compliance options, some of which could entail significant capital expenditures to implement, will be applicable to its facilities.

Collective bargaining agreements. As of September 30, 2008, approximately 58% of the electric utilities’ employees were members of the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260, Unit 8, which is the only union representing employees of the Company. On March 1, 2008, members of the union ratified new collective bargaining and benefit agreements with HECO, HELCO and MECO. The new agreements cover a three-year term, from November 1, 2007 to October 31, 2010, and provide for non-compounded wage increases of 3.5% effective November 1, 2007, 4% effective January 1, 2009 and 4.5% effective January 1, 2010.

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

(6) Cash flows

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

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

Supplemental disclosure of noncash activities. The allowance for equity funds used during construction, which was charged to construction in progress as part of the cost of electric utility plant, amounted to $6.4 million and $3.8 million for the nine months ended September 30, 2008 and 2007, respectively.

(7) Recent accounting pronouncements and interpretations

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

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


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

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

(9) Consolidating financial information

HECO is not required to provide separate financial statements or other disclosures concerning HELCO and MECO to holders of the 2004 Debentures issued by HELCO and MECO to Trust III since all of their voting capital stock is owned, and their obligations with respect to these securities have been fully and unconditionally guaranteed, on a subordinated basis, by HECO. Consolidating information is provided below for these and other HECO subsidiaries for the periods ended and as of the dates indicated. As of the dates and for the periods presented for 2007, there were no amounts for Uluwehiokama Biofuels Corp., a newly-formed, unregulated HECO subsidiary.

HECO also unconditionally guarantees HELCO’s and MECO’s obligations (a) to the State of Hawaii for the repayment of principal and interest on Special Purpose Revenue Bonds issued for the benefit of HELCO and MECO and (b) relating to the trust preferred securities of Trust III. Also, see Note 2. HECO is also obligated, after the satisfaction of its obligations on its own preferred stock, to make dividend, redemption and liquidation payments on HELCO’s and MECO’s preferred stock if the respective subsidiary is unable to make such payments.

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Three months ended September 30, 2008


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

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

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

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

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

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

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

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

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

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

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Three months ended September 30, 2007


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

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

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

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

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

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

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

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

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

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

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Nine months ended September 30, 2008


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

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

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

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

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

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

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

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

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

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

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Nine months ended September 30, 2007


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

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

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

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

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

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

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

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

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

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

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

September 30, 2008


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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

December 31, 2007


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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Common Stock Equity (unaudited)

Nine months ended September 30, 2008


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

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

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

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Common Stock Equity (unaudited)

Nine months ended September 30, 2007


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

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

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

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Nine months ended September 30, 2008


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

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

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

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

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

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

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

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Nine months ended September 30, 2007


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

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

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

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

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

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

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

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

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

The following discussion updates “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in HEI’s and HECO’s Form 10-K for the year ended December 31, 2007 and should be read in conjunction with the annual (as of and for the year ended December 31, 2007) and quarterly (as of and for the three months ended March 31, 2008, and as of and for the three and six months ended June 30, 2008) consolidated financial statements of HEI and HECO and accompanying notes.

HEI CONSOLIDATED

RESULTS OF OPERATIONS


(in thousands, except per share amounts)	Three months ended September 30				% change	Primary reason(s) for significant change *
(in thousands, except per share amounts)	2008		2007		% change	Primary reason(s) for significant change *
Revenues	$	915,431	$	673,461	36	Increase for the electric utility segment, partly offset by decreases for the bank and “other” segments

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

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

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

Weighted-average number of common shares outstanding		84,625		82,481	3	Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other Company plans

(in thousands, except per share amounts)	Nine months ended September 30				% change	Primary reason(s) for significant change *
(in thousands, except per share amounts)	2008		2007		% change	Primary reason(s) for significant change *
Revenues	$	2,419,103	$	1,828,247	32	Increase for the electric utility segment, partly offset by decreases for the bank and “other” segments

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

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

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

Weighted-average number of common shares outstanding		84,052		81,949	3	Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other Company plans

*	Also, see segment discussions which follow.

The Company’s effective tax rates (federal and state) for the third quarters of 2008 and 2007 were 35% and 34%, respectively. The Company’s effective tax rates for the first nine months of 2008 and 2007 were 35% and 34%, respectively. The effective tax rates were slightly lower in 2007 than in 2008 due primarily to state tax credits.

Dividends

On October 31, 2008, the HEI Board of Directors (Board) maintained the quarterly dividend of $0.31 per common share. The payout ratios for 2007 and the first nine months of 2008 were 120% and 102%, respectively. Excluding the net income impact ($35.6 million) of ASB’s balance sheet restructuring, the payout ratio for the first nine months of 2008 would have been 70%. HEI’s Board believes that HEI should have a payout ratio of 65% or lower on a sustainable basis and that cash flows should support an increase before it considers increasing the common stock dividend above its current level.

Economic conditions

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

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

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

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

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

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

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

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

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

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

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

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

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

Emergency Economic Stabilization Act of 2008

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

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

Retirement benefits

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

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


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

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

“Other” segment


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

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

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


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

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

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

NM Not meaningful.

The “other” business segment includes results of operations of HEI Investments, Inc. (HEIII), a company previously holding investments in leveraged leases; Pacific Energy Conservation Services, Inc., a contract services company primarily providing wind farm operational and maintenance services to an affiliated electric utility; HEI Properties, Inc., a company holding passive, venture capital investments; The Old Oahu Tug Service, Inc., which was previously a maritime freight transportation company that ceased operations in 1999 and now is largely inactive; HEI and HEIDI, holding companies; and eliminations of intercompany transactions. Since HEIII sold all of its leveraged lease investments by the end of 2007, HEIII has filed articles of dissolution and is winding up its affairs.

Commitments and contingencies

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

Recent accounting pronouncements and interpretations

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

FINANCIAL CONDITION

Liquidity and capital resources

Despite the recent unprecedented deterioration in the capital markets and tightening of credit, the Company believes that its ability to generate cash, both internally from electric utility and banking operations and externally from issuances of equity and debt securities, commercial paper and bank borrowings, is adequate to maintain sufficient liquidity to fund its contractual obligations and commercial commitments, its forecasted capital expenditures and investments, its expected retirement benefit plan contributions and other cash requirements in the foreseeable future.

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


(in millions)	September 30, 2008				December 31, 2007
Short-term borrowings—other than bank	$	231	8	%	$	92	4	%
Long-term debt, net—other than bank		1,211	44			1,242	47
Preferred stock of subsidiaries		34	1			34	1
Common stock equity		1,321	47			1,275	48

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

As of October 31, 2008, the Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HEI securities were as follows:


	S&P	Moody’s
Commercial paper	A-2	P-2
Senior unsecured debt	BBB	Baa2

The above ratings reflect only the view of the applicable rating agency at the time the ratings are issued, from whom an explanation of the significance of such ratings may be obtained. Such ratings are not recommendations to buy, sell or hold any securities; such ratings may be subject to revision or withdrawal at any time by the rating agencies; and each rating should be evaluated independently of any other rating.

HEI’s overall S&P corporate credit rating is BBB/Stable/A-2 and Moody’s outlook for HEI is “stable.”

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

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

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

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

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

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

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


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

	$	169	$	231	$	92

Line of credit facility (expiring March 31, 2011) ¹			$	100	$	100
Undrawn capacity under HEI’s line of credit facility ²				60		100

¹	In the future, Company may seek to enter into new lines of credit and may also seek to increase the amount of credit available under such lines as management deems appropriate.

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

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

As of September 30, 2008, $96 million of debt, equity and/or other securities were available for offering by HEI under an omnibus shelf registration and an additional $50 million principal amount of Series D notes were available for offering by HEI under its registered medium-term note program. Under SEC regulations, these two registrations will expire or be terminated by November 30, 2008. After the filing of this report on Form 10-Q, HEI plans to file a new omnibus registration statement to register an indeterminate amount of debt, equity and hybrid securities. Under SEC regulations, this new registration statement, when filed, would expire in three years.

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

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

CERTAIN FACTORS THAT MAY AFFECT FUTURE RESULTS AND FINANCIAL CONDITION

The Company’s results of operations and financial condition can be affected by numerous factors, many of which are beyond the Company’s control and could cause future results of operations to differ materially from historical results. For information about certain of these factors, see pages 12 to 13, 36 to 40, and 47 to 49 of HEI’s MD&A which is incorporated into Part II, Item 7 of HEI’s 2007 Form 10-K by reference to HEI Exhibit 13 to HEI’s Current Report on Form 8-K dated February 21, 2008.

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

MATERIAL ESTIMATES AND CRITICAL ACCOUNTING POLICIES

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

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

For information about these material estimates and critical accounting policies, see pages 13 to 14, 40 to 41, and 49 of HEI’s MD&A which is incorporated into Part II, Item 7 of HEI’s 2007 Form 10-K by reference to HEI Exhibit 13 to HEI’s Current Report on Form 8-K dated February 21, 2008.

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

ELECTRIC UTILITIES

Executive overview and strategy—recent development

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

RESULTS OF OPERATIONS


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

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

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

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

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

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


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

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

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

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

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

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

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

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

Results – three months ended September 30, 2008

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

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

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

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

Results – nine months ended September 30, 2008

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

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

Renewable energy strategy

The electric utilities have been taking actions intended to protect Hawaii’s island ecology and counter global warming, while continuing to provide reliable power to customers, and recently committed to a number of related actions in the Energy Agreement entered into with the State. A three-pronged strategy supports attainment of the requirements and goals of the State of Hawaii RPS, the Hawaii Global Warming Solutions Act of 2007 and the HCEI by: 1) the greening of existing assets, 2) the expansion of renewable energy generation and 3) the

acceleration of energy efficiency and load management programs. Major initiatives are being pursued in each category, and additional ones have been committed to in the Energy Agreement.

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

The electric utilities are actively exploring the use of biofuels for existing and planned company-owned generating units. HECO has committed to using 100% biofuels for its new 110 MW generating unit planned for 2009. HECO is researching the possibility of switching its steam generating units from fossil fuels to biofuels, and in the Energy Agreement has committed to do so if economically and technically feasible and if adequate biofuels are available.

In January 2007, HECO and MECO agreed to form a venture with BlueEarth Biofuels LLC (BlueEarth) to develop a biodiesel production facility on MECO property in Wa’ena on the island of Maui. BlueEarth Maui Biofuels LLC (BlueEarth Maui), a joint venture to pursue biodiesel development, was recently formed between BlueEarth and Uluwehiokama Biofuels Corp. (UBC), a non-regulated subsidiary of HECO. In February 2008, an Operating Agreement and an Investment Agreement were executed between BlueEarth and UBC, under which UBC invested $400,000 in BlueEarth Maui in exchange for a minority ownership interest. All of UBC’s profits from the project will be directed into a biofuels public trust to be created for the purpose of funding biofuels development in Hawaii. MECO intends to lease a portion of the land owned by MECO for its future Waena generation station as the site for the biodiesel plant, with lease proceeds to be credited to MECO ratepayers. MECO has been negotiating with BlueEarth Maui for a fuel purchase contract for biodiesel to be used in existing diesel-fired units at MECO’s Maalaea plant. Both the land lease agreement and biodiesel fuel contract will require PUC approval. Although not required to do so, BlueEarth Maui has also announced plans to prepare an environmental impact study for the project. HECO, working closely with the Natural Resources Defense Council, developed an environmental policy, which focuses on sustainable palm oil and locally-grown feedstocks, to ensure that the project would procure biofuel and biofuel feedstocks only from sustainable sources. Recently, BlueEarth’s and MECO’s negotiations for the biodiesel supply contract stalled based on an inability to reach agreement on various financial and risk allocation issues. In October 2008, BlueEarth filed an action in federal district court in Texas against MECO, HECO and others alleging claims based on the parties’ failure to have reached agreement on the biodiesel supply and land agreements. The lawsuit seeks unspecified damages and equitable relief. The parties are currently exploring the possibility of amicably resolving their disputes and the litigation.

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

HECO’s unregulated subsidiary, Renewable Hawaii, Inc. (RHI), is seeking to stimulate renewable energy initiatives by prospecting for new projects and sites and taking a passive, minority interest in selected third party renewable energy projects. Since 2003, RHI has actively pursued a number of solicited and unsolicited projects, particularly those utilizing wind, landfill gas, and ocean energy. RHI will generally make project investments only after

developers secure the necessary approvals and permits and independently execute a PUC-approved PPA with HECO, HELCO or MECO. While RHI has executed some memoranda of understanding and conditional investment agreements with project developers, no investments have been made to date.

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

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

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

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

Competition

Although competition in the generation sector in Hawaii has been moderated by the scarcity of generation sites, various permitting processes and lack of interconnections to other electric utilities, HECO and its subsidiaries face competition from IPPs and customer self-generation.

In October 2003, the PUC opened investigative proceedings on two specific issues (competitive bidding and DG) to move toward a more competitive electric industry environment under cost-based regulation. For a description of some of the regulatory changes that will be pursued as part of the Energy Agreement, see “Hawaii Clean Energy Initiative (HCEI)” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.”

Competitive bidding proceeding . The stated purpose of this proceeding was to evaluate competitive bidding as a mechanism for acquiring or building new generating capacity in Hawaii. In December 2006, the PUC issued a decision that included a final competitive bidding framework, which became effective immediately. In 2007, the PUC approved the utilities’ tariffs containing procedures for interconnection and transmission upgrades, a list of qualified candidates for the Independent Observer position for future competitive bidding processes and a Code of Conduct.

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

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

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

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

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

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

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

In January 2006, the PUC issued its D&O indicating that its policy is to promote the development of a market structure that assures DG is available at the lowest feasible cost, DG that is economical and reliable has an opportunity to come to fruition and DG that is not cost-effective does not enter the system. The D&O affirmed the ability of the utilities to procure and operate DG for utility purposes at utility sites. The PUC also indicated its desire to promote the development of a competitive market for customer-sited DG. The PUC found that the “disadvantages outweigh the advantages” of allowing a utility to provide DG services on a customer’s site. However, the PUC also found that the utility “is the most informed potential provider of DG” and it would not be in the public interest to exclude the utilities from providing DG services at this early stage of DG market development. Therefore, the D&O allows the utility to provide DG services on a customer-owned site as a regulated service when (1) the DG resolves a legitimate system need, (2) the DG is the lowest cost alternative to meet that need, and (3) it can be shown that, in an open and competitive process acceptable to the PUC, the customer operator was unable to find another entity ready and able to supply the proposed DG service at a price and quality comparable to the utility’s offering.

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

The utilities are developing or evaluating potential DG projects. In September 2008, HECO executed an agreement with the State of Hawaii Department of Transportation to develop a dispatchable standby generation (DSG) facility at the Honolulu Airport that will be owned by the State and operated by HECO. The D&O encouraged HECO to pursue such DG operating arrangements with customers. HECO will file an application to the PUC for approval of the agreement in the fourth quarter 2008.

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

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

The January 2006 D&O also required the utilities to file tariffs and establish standby rates based on unbundled costs associated with providing each service (i.e., generation, distribution, transmission and ancillary services). The utilities filed their proposed modifications to existing DG interconnection tariffs and their proposed unbundled standby rates for PUC approval in the third quarter of 2006. The Consumer Advocate stated that it did not object to implementation of the interconnection and standby rate tariffs at the present time, but reserved the right to review the reasonableness of both tariffs in rate proceedings for each of the utilities. See “Distributed generation tariff proceeding” below.

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

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

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

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

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

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

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

Most recent rate requests

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

As of October 31, 2008, the ROACE found by the PUC to be reasonable in the most recent final rate decision for each utility was 10.7% for HECO (D&O issued on May 1, 2008, based on a 2005 test year), 11.5% for HELCO (D&O issued on February 8, 2001, based on a 2000 test year) and 10.94% for MECO (amended D&O issued on April 6, 1999, based on a 1999 test year). The ROACEs used by the PUC in the interim rate increases in HECO,

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

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

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

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

For a description of some of the rate-making changes that the parties have agreed to pursue under the Energy Agreement, see “Hawaii Clean Energy Initiative (HCEI)” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.”

HECO.

2005 test year rate case . In November 2004, HECO filed a request with the PUC to increase base rates, based on a 2005 test year, a 9.11% ROR and an 11.5% ROACE. Disregarding an amount included in the request to transfer the cost of existing DSM programs from a surcharge line item on electric bills into base electricity charges, the requested base rates increase was $74 million, or 7.3%.

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

Later in September 2005, the PUC issued its interim D&O, authorizing an increase of $53 million ($41 million net additional revenues). For purposes of the interim D&O, the PUC included HECO’s prepaid pension asset in rate base (with an annual rate increase impact of approximately $7 million).

On October 25, 2007, the PUC issued an amended proposed final D&O, authorizing a net increase of 2.7%, or $34 million, in annual revenues, based on a 10.7% ROACE (and an 8.66% ROR on a rate base of $1.060 billion). The amended proposed final D&O, which has now been issued in final form with certain modifications (as described below), reversed the portion of the interim D&O related to the inclusion of HECO’s approximately $50 million pension asset, net of deferred income taxes, in rate base, and required a refund of revenues associated with that reversal, including interest, retroactive to September 28, 2005 (the date the interim increase became effective). In the third quarter of 2007, HECO accrued $15 million for the potential customer refunds, reducing third quarter 2007 net income by $8.3 million. The potential additional refund to customers for the amounts recorded under interim rates in excess of the amount in the amended proposed final D&O from October 1, 2007 through October 21, 2007, with interest through July 19, 2008, was approximately $1.8 million, which amount was reserved for the refund and included an adjustment for the interest synchronization method adopted by the PUC (as proposed by the DOD in its filed exception to the proposed final D&O).

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

2007 test year rate case . On December 22, 2006, HECO filed a request with the PUC for a general rate increase of $99.6 million, or 7.1% over the electric rates currently in effect (i.e., over rates that included the interim rate increase discussed above of $53 million ($41 million net additional revenues) granted by the PUC in September 2005), based on a 2007 test year, an 8.92% ROR, an 11.25% ROACE and a $1.214 billion average rate base. This rate case excluded DSM surcharge revenues and associated incremental DSM costs because certain DSM issues, including cost recovery, were being addressed in the EE DSM Docket.

HECO’s 2006 application included a proposed new tiered rate structure for residential customers to reward customers who practice energy conservation with lower electric rates for lower monthly usage. The proposed rate increase includes costs incurred to maintain and improve reliability, such as the new Dispatch Center building and associated equipment and the Energy Management System that became operational in 2006, new substations, a new outage management system (added in 2007) and increased O&M expenses. The application addresses the ECAC provisions of Act 162 and requests the continuation of HECO’s ECAC.

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

HECO’s application requested a return on HECO’s pension assets (i.e., accumulated contributions in excess of accumulated net periodic pension costs) by including such assets (net of deferred taxes) in rate base. In a separate AOCI proceeding, the electric utilities had earlier requested PUC approval to record as a regulatory asset for financial reporting purposes, the amounts that would otherwise be charged to AOCI in stockholders’ equity as a result of adopting SFAS No. 158, but that request was denied. HECO thus proposed in the 2007 test year rate case to restore to book equity for ratemaking purposes the amounts charged to AOCI as a result of adopting SFAS No. 158. The authorized ROACE found to be fair in a rate case is applied to the equity balance in determining the utility’s weighted cost of capital, which is the rate of return applied to the rate base in determining the utility’s revenue requirements. HECO’s position was that, if the reduction in equity balance resulting from the AOCI charges is not restored for ratemaking purposes, a higher ROACE will be required.

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

In a June 2007 update to its direct testimonies, HECO proposed pension and OPEB tracking mechanisms, similar to the mechanisms that were agreed to by HELCO and the Consumer Advocate and approved on an interim basis by the PUC in the HELCO 2006 test year rate case. A pension funding study (required by the PUC in the AOCI proceeding) was filed in the HECO rate case in May 2007. The conclusions in the study were consistent

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

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

The amount of the revenue increase based on the stipulated agreement was $70 million annually, or a 4.96% increase over current effective rates at the time of the stipulation. The settlement agreement included, as a negotiated compromise of the parties’ respective positions, an ROACE of 10.7% (and an 8.62% ROR of $1.158 billion) to determine revenue requirements in the proceeding. In the settlement agreement, the parties agreed that the final rates set in HECO’s 2005 test year rate case may impact revenues at current effective rates and at present rates, and indicated that the amount of the stipulated interim rate increase would be adjusted to take into account any such changes. For purposes of the settlement, the parties agreed to a pension tracking mechanism that does not include amortization of HECO’s pension asset (comprised of accumulated contributions to its pension plan in excess of net periodic pension cost and amounting to $68 million at December 31, 2006) as part of the pension tracking mechanism in the proceeding. (This has the effect of deferring the issue of whether the pension asset should be amortized for rate making purposes to HECO’s next rate case.)

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

On October 22, 2007, the PUC issued, and HECO implemented, an interim D&O granting HECO an increase of $70 million in annual revenues over rates effective at the time of the interim D&O, subject to refund with interest. The interim increase is based on the settlement agreement described above and did not include in rate base the HECO pension asset. The interim D&O also approves, on an interim basis, the adoption of the pension tracking mechanism and a tracking mechanism for OPEB. See “Interim increases” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.”

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

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

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

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

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

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

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

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

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

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

The PUC held public hearings on HELCO’s application in June 2006. In February 2007, the Consumer Advocate submitted its testimony in the proceeding, recommending a revenue increase of $16.6 million based on its proposed ROR of 7.95%, a ROACE ranging between 9.50% and 10.25% and a proposed average rate base of $345 million. The Consumer Advocate recommended adjustments of $21.5 million to HELCO’s rate base for a portion of CT-4 and CT-5 costs (primarily relating to HELCO’s AFUDC, land use permitting costs, and related litigation expenses). In the filing, the Consumer Advocate’s consultant concluded that HELCO’s ECAC provides a fair sharing of the risks of fuel cost changes between HELCO and its ratepayers in a manner that preserves the financial integrity of HELCO without the need for frequent rate filings. In July 2008, HELCO submitted responses to information requests from the PUC regarding the impacts of passing changes in fuel and purchased energy costs to customers through the ECAC.

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

In March 2007, HELCO and the Consumer Advocate reached settlement agreements on all revenue requirement issues in the HELCO 2006 rate case proceeding, which were documented in an April 5, 2007 settlement letter. Under the revenue requirement agreement, HELCO agreed to write-off a portion of CT-4 and CT-5 costs, which resulted in an after-tax charge of approximately $7 million in the first quarter of 2007.

On April 4, 2007, the PUC issued an interim D&O, which was implemented by tariff changes made effective on April 5, 2007, granting HELCO an increase of 7.58%, or $24.6 million in annual revenues, over revenues at present rates for a normalized 2006 test year. The interim increase reflects the settlement of the revenue requirement issues reached between HELCO and the Consumer Advocate and is based on an average rate base of $357 million (which reflects the write-off of a portion of CT-4 and CT-5 costs) and an ROR of 8.33% (incorporating an ROACE of 10.7%). In the interim D&O, the PUC also approved on an interim basis the adoption of pension and OPEB tracking mechanisms.

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

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

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

In an update to its direct testimonies filed in September 2007, MECO proposed a lower increase in annual revenues of $18.3 million, or 5.1%, but its request continued to be based on an 8.98% ROR and an 11.25% ROACE. Also in the update, MECO proposed tracking mechanisms for pension and OPEB, similar to the mechanisms proposed by HECO and HELCO, and approved by the PUC on an interim basis, in their 2007 and 2006 test year rate cases, respectively. In October 2007, the Consumer Advocate filed its direct testimony which recommended a revenue increase of $8.9 million, based on a ROR of 8.29% and a ROACE of 10.0%. $4.75 million of the $9.4 million difference between MECO’s and the Consumer Advocate’s proposed increase is caused by the Consumer Advocate’s lower recommended ROR and ROACE.

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

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

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

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

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

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

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

In addition, the PUC required that the administration of all EE DSM programs be turned over to a non-utility, third-party administrator, with the transition to the administrator, funded through a public benefits fund (PBF) surcharge, to become effective around January 2009. The PUC opened a new docket to select a third-party administrator and to refine details of the new market structure in an order issued in September 2007. In the order, the PUC stated that “[u]pon selection of the PBF Administrator, the PUC intends, in this docket, to determine whether the electric utilities will be allowed to compete for the implementation of the Energy Efficiency DSM programs.” The PUC has issued a draft RFP for the PBF Administrator. In July 2008, the PUC issued an Order to Initiate the Collection of Funds for the PBF Administrator of Energy Efficiency Programs, which authorized the electric utilities to expense $50,000 per quarter beginning July 1, 2008 for the initial start-up costs associated with the PBF Administrator and recover the cost in the DSM surcharge; confirmed that the load management, SolarSaver and RCEA programs shall remain with the electric utilities; directed the electric utilities to continue to operate the DSM programs through June 30, 2009, and after the transition period, the electric utilities can compete for implementation of DSM programs as a subcontractor.

The EE Docket D&O also provides for HECO’s recovery of DSM program costs and utility incentives. With respect to cost recovery, the PUC continues to permit recovery of reasonably-incurred DSM implementation costs, under the IRP framework. DSM utility incentives will be derived from a graduated performance-based schedule of net system benefits. In order to qualify for an incentive, the utility must meet MW and MWh reduction goals for its EE DSM programs in both the commercial and industrial sector, and the residential sector. The amount of the annual incentive is capped at $4 million for HECO, and may not exceed either 5% of the net system benefits, or utility earnings opportunities foregone by implementing DSM programs in lieu of supply-side rate based investments. Negative incentives will not be imposed for underperformance. In 2007, HECO recorded incentives of $4 million. HELCO and MECO proposed goals for their programs, based on the goals established for HECO’s programs, but recorded no incentives in 2007. In June 2008, the PUC issued an order approving MECO’s proposed cumulative energy and demand savings goals for 2007 and 2008, but set MECO’s annual incentive cap at $320,000. Thus, in the second quarter of 2008, MECO recorded an incentive of $320,000 related to 2007. A decision on HELCO’s proposed goals is pending. The utilities’ DSM incentives for 2008 are subject to adjustment based on the results of impact evaluation reports and may be lower than 2007 incentives. Additionally, in October 2008, HECO requested the PUC to authorize higher 2008 DSM incentive budgets. If approval of these higher budgets is not received, it could result in lower 2008 incentives.

Unlike the EE DSM programs, load management DSM programs will continue to be administered by the utilities. HECO’s residential load management program includes a monthly electric bill credit for eligible customers who participate in the program, which allows HECO to disconnect the customer’s residential electric water heaters or central air conditioning systems from HECO’s system to reduce system load when deemed necessary by HECO. The commercial and industrial load management program provides an incentive on the portion of the demand load that eligible customers allow to be controlled or interrupted by HECO. This program includes small business direct load control and voluntary program elements.

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

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

Avoided cost generic docket . In May 1992, the PUC instituted a generic investigation to examine the proxy method and formula used by the electric utilities to calculate their avoided energy costs and Schedule Q rates. In general, Schedule Q rates are available to customers with cogeneration and/or small power production facilities with a capacity of 100 KWHs or less who buy power from or sell power to the electric utility. In March 1994, the parties to the docket entered into a Stipulation to Resolve Proceeding, which was subject to PUC approval. In December 2006, the parties filed an updated stipulation with the PUC. The parties agreed that avoided fuel costs, except for Lanai and Molokai, will be determined using a computer production simulation model and agreed on certain parameters that would be used to calculate avoided costs. In March 2008, the PUC issued an order which approved the updated stipulation and ordered that the new avoided energy cost rates and Schedule Q rates will go into effect on August 1, 2008. HECO, HELCO and MECO filed new avoided energy costs rates and Schedule Q rates, which were determined using the new “resource-in / resource-out” methodology instead of the proxy method. These rates are effective from August 1 through December 31, 2008, and the fuel component of the rates will adjust monthly for changes in fuel prices.

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

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

The utilities are entitled to recover all appropriate and reasonable integrated resource planning and implementation costs, including the costs of DSM programs, either through a surcharge or through their base rates. Under procedural schedules for the IRP cost proceedings, the utilities were able to recover their incremental IRP costs in the month following the filing of their actual costs incurred for the year, subject to refund with interest pending the PUC’s final D&O approving recovery in the docket for each year’s costs. HELCO (since February 2001), HECO (since September 2005) and MECO (since December 2007) now recover IRP costs (which are included in O&M) through base rates. Previously, HECO, HELCO and MECO recovered their costs through a surcharge. The Consumer Advocate has objected to the recovery of $1.5 million (before interest) of the $4.3 million of incremental IRP costs incurred by the utilities during the 2000-2006 period, and the PUC’s decisions are pending on these costs. Also, see Note 5 in HECO’s “Notes to Consolidated Financial Statements” and “Demand-side management programs” above.

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

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

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

HELCO’s IRP . In May 2007, HELCO filed its third IRP, which proposes multiple solutions to meet future energy needs on the island of Hawaii. The plan includes the installation of a nominal 16 MW steam turbine (ST-7) in 2009 at its Keahole Generating Station (see “Major projects” in Note 5 of HECO’s “Notes to Consolidated Financial Statements”). The plan also follows through on a commitment to have no new fossil-fired generation installed after ST-7. The plan anticipates increasing customer photovoltaic systems plus a 37 gigawatthours per year renewable energy resource in the 2014 to 2020 timeframe, a firm capacity renewable energy resource in 2022, energy efficiency (continuation of existing DSM programs) and CHP. In November 2007, HELCO and the Consumer Advocate filed a stipulated agreement which recommended that the PUC approve HELCO’s IRP-3 and in which HELCO agreed to make improvements to the IRP process and to submit evaluation reports by March 31, 2009 and March 31, 2010. In January 2008, the PUC issued its D&O approving HELCO’s IRP-3 and required HELCO to submit annual evaluation reports by March 31, 2009 and March 31, 2010 and file its IRP-4 by May 31, 2010.

MECO’s IRP . In April 2007, MECO filed its third IRP, which proposes multiple solutions to meet future energy needs on the islands of Maui, Lanai and Molokai, including renewable energy resources (such as photovoltaics, additional wind, biomass and waste-to-energy), energy efficiency (continuation of existing and addition of new DSM programs), technology (such as CHP and DG) and competitive bidding for generation or blocks of generation on Maui for 20 MW in each of 2011 and 2013 and 18 MW in 2024 which, under the utility parallel plan, could be located at its Waena site. In July 2008, the PUC approved MECO’s IRP-3 and directed MECO to submit evaluation reports by December 31, 2008 and December 31, 2009, to make various improvements to the IRP process and to submit its IRP-4 by April 30, 2010.

The PPA between MECO and Hawaiian Commercial & Sugar Company (HC&S), which provides for 16 MW of firm capacity, continues in effect from year to year, subject to termination on written notice by either party of not less than two years. In July 2007, however, the parties agreed to not issue a notice of termination that would result

in the termination of the PPA prior to the end of 2014. In June 2008, MECO developed a new sales and peak forecast, which projects lower sales and peaks compared to the previous, July 2007, forecast. In July 2008, MECO filed an update to its 2008 Adequacy of Supply letter in which it indicated that the date the next increment of additional firm generating capacity on Maui is needed has changed from 2011 to 2014.

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

Adequacy of supply.

HECO . HECO’s 2008 Adequacy of Supply (AOS) letter, filed in January 2008, indicates that HECO’s analysis estimates its reserve capacity shortfall to be approximately 80 MW in the 2008 to 2009 period (before the addition of the Campbell Industrial Park combustion turbine planned to be installed in 2009). The availability rates for HECO units have generally declined since 2002 and, based on this experience, the manner in which the units must be operated when there is a reserve capacity shortfall, and the increasing ages of the units, HECO expects availability rates to remain suppressed in the near-term. Although the availability rates for generating units on Oahu continue to be better than those of comparable units on the U.S. mainland, HECO generating units may continue to be entirely or partially unavailable to serve load during scheduled overhaul periods and other planned maintenance outages, or when they “trip” or are taken out of operation or their output is “de-rated” due to equipment failure or other causes.

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

After the planned 2009 addition of the Campbell Industrial Park generating unit, and in recognition of the uncertainty underlying key forecasts, HECO reported in its 2008 AOS letter that it anticipates the potential for continued reserve capacity shortfalls could range between 20 MW to 80 MW in 2010, up to a range of 70 MW to 130 MW in 2014, and may seek a firm, dispatchable resource (with a strong preference for a renewable resource) to meet this need, while continuing contingency planning activities. Any plan to seek additional firm capacity is required to proceed under the guidance of the Competitive Bidding Framework issued by the PUC in December 2006. On September 30, 2008, HECO submitted to the PUC its IRP-4, which noted that a short-term sales and peak forecast was developed in March 2008. Analysis indicated that the reserve capacity shortfall could range from 0 MW to 20 MW in 2011 and from 50 MW to 80 MW in 2014. As stated earlier (see “HECO’s IRP” above), HECO plans to pursue the installation of a second 100 MW biofueled combustion turbine at its Campbell Industrial Park generating station in the 2011-2012 timeframe. HECO also plans to remove a 46 MW oil-fired cycling unit from service after the second combustion turbine is in service, and will later determine whether to place the unit in emergency reserve status or to retire the unit.

HECO’s gross peak demand was 1,327 MW in 2004, 1,273 MW in 2005, 1,315 MW in 2006 and 1,261 MW in 2007. Peak demand may vary from year to year, but over time, demand for electricity on Oahu is projected to increase. On occasions in 2004, 2005, 2006 and 2007, HECO issued public requests that its customers voluntarily conserve electricity as generating units were out for scheduled maintenance or were unexpectedly unavailable. In addition to making the requests, in 2005, 2006 and 2007, HECO on occasion remotely turned off water heaters for a number of residential customers who participate in its load-control program.

HELCO . HELCO’s 2008 Adequacy of Supply letter filed in January 2008 indicated that HELCO’s generation capacity for the next three years, 2008 through 2010, is sufficiently large to meet all reasonably expected demands for service and provide reasonable reserves for emergencies.

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

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

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

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

October 2006 outages . On Sunday, October 15, 2006, shortly after 7 a.m., two earthquakes centered on the island of Hawaii with magnitudes of 6.7 and 6.0 triggered power outages throughout most of the state and disrupted air traffic on all major islands. On Oahu, following the impact of the earthquakes, a series of protective actions and automatic systems operated to successively shut down all generators to protect them from potential damage. As a result, no significant damage to any of HECO’s generators, or to its transmission and distribution systems, occurred. Following the island-wide outage, HECO restored power to customers in a careful, methodical manner to further protect its system, and as a result power was restored to over 99% of its customers within a period of time ranging from approximately 4 ¹ / 2 to 18 hours. Management believes the shutdown and methodical restoration of power were necessary to prevent severe damage to HECO’s generating equipment and power grid and to avoid a more prolonged blackout. HELCO’s and MECO’s smaller electric systems also experienced sustained outages from the earthquakes; however, their systems were, for the most part, back online by mid to late afternoon .

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

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

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

Intra-governmental wheeling of electricity . In June 2007, the PUC initiated a docket to examine the feasibility of implementing intra-governmental wheeling of electricity in the State of Hawaii. The issues in the proceeding adopted by the PUC include (1) identifying what impact, if any, wheeling will have on Hawaii’s electric industry, (2) addressing interconnection matters, (3) identifying the costs to utilities, (4) identifying any rate design and cost allocation issues, (5) considering the financial cost and impact on non-wheeling customers, (6) identifying any power back-up issues, (7) addressing how rates would be set, (8) identifying the environmental impacts, (9) identifying and evaluating the various forms of intra-governmental wheeling and (10) identifying and evaluating the resulting impact to any and all governmental entities, including but not limited to economic, feasibility and liability impacts. Parties to this proceeding include HECO, HELCO, MECO, Kauai Island Utility Cooperative and the Consumer Advocate, as well as governmental agencies (the DOD, the DBEDT, the City and County of Honolulu and the Counties of Hawaii, Maui and Kauai), an environmental group, and two renewable energy developers. Two renewable energy contractors and a renewable energy developer also have been granted more limited participant status. The procedural schedule includes technical workshops and meetings through December 2008, with a formal process to commence thereafter.

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

Collective bargaining agreements

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

Legislation and regulation

Congress and the Hawaii legislature periodically consider legislation that could have positive or negative effects on the utilities and their customers. Also see “Hawaii Clean Energy Initiative (HCEI)” and “Environmental regulation” in Note 5 of HECO’s “Notes to Consolidated Financial Statements” and “Emergency Economic Stabilization Act of 2008” above.

Energy Policy Act of 2005 . On August 8, 2005, the President signed into law the Energy Policy Act of 2005 (the Act). The Act provides $14.5 billion in tax incentives over a 10-year period designed to boost conservation efforts, increase domestic energy production and expand the use of alternative energy sources, such as solar, wind, ethanol, biomass, hydropower and clean coal technology. Ocean energy sources, including wave power, are identified as renewable technologies. Section 355 of the Act authorizes a study by the U.S. Department of Energy of Hawaii’s dependence on oil; however, that provision is subject to appropriation, as is $9 million authorized under Section 208 for a sugar cane ethanol program in Hawaii. No funds have been appropriated to date. Incentives also include tax credits and shorter depreciable lives for many assets associated with energy production and transmission. The Act’s primary direct impact on HECO and its subsidiaries is currently expected to be the reduction in the depreciable tax life, from 20 years to 15 years, of certain electric transmission equipment placed into service after April 11, 2005.

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

The RPS law provides that at least 50% of the RPS targets must be met by electrical energy generated using renewable energy sources, such as wind or solar, versus from the electrical energy savings from renewable energy displacement technologies (such as solar water heating) or from energy efficiency and conservation programs. The RPS law also provides for penalties to be established by the PUC if the RPS requirements are not

met and criteria for waiver of the penalties by the PUC, if the requirements cannot be met due to circumstances beyond the electric utility’s control.

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

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

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

In its December 2007 decision and order, the PUC deferred the RPS incentive framework to a new generic docket (Renewable Energy Infrastructure Program or REIP Docket). The Renewable Energy Infrastructure Program proposed by HECO consists of two components: (1) renewable energy infrastructure projects that facilitate third-party development of renewable energy resources, maintain existing renewable energy resources and/or enhance energy choices for customers, and (2) the creation and implementation of a temporary renewable energy infrastructure surcharge to recover the capital costs, deferred costs for software development and licenses, and/or other relevant costs approved by the PUC. These costs would be removed from the surcharge and included in base rates in the utility’s next rate case. The parties to the REIP Docket include the electric utilities, the Consumer Advocate, an environmental organization and Hawaii Renewable Energy Alliance (HREA). Public hearings were held in May 2008. In July 2008, statements of position were filed with the PUC, in which the Consumer Advocate recommended approval of, HREA supported, and the environmental organization did not oppose the REIP proposed by HECO. In October 2008, pursuant to the PUC’s request, the parties to the docket informed the PUC, among other things, that the parties (1) have reached an agreement on all of the issues in the docket, (2) agree that it is appropriate that the PUC approve the utilities’ proposed REIP and related REIP surcharge, (3) agree that the record in the proceeding is complete and ready for PUC decision-making, and (4) waive an evidentiary hearing.

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

Management cannot predict the outcome of these processes.

Net energy metering . Hawaii has a net energy metering law, which requires that electric utilities offer net energy metering to eligible customer generators (i.e., a customer generator may be a net user or supplier of energy and will make payment to or receive credit from the electric utility accordingly).

In 2005, the Legislature amended the net energy metering law by, among other revisions, authorizing the PUC, by rule or order, to increase the maximum size of the eligible net metered systems and to increase the total rated generating capacity available for net energy metering. In April 2006, the PUC initiated an investigative proceeding on whether the PUC should increase (1) the maximum capacity of eligible customer-generators to more than 50 kilowatts (kw) and (2) the total rated generating capacity produced by eligible customer-generators to an amount above 0.5% of an electric utility’s system peak demand. The parties to the proceeding include HECO, HELCO, MECO, Kauai Island Utility Cooperative (KIUC), the Consumer Advocate, a renewable energy organization and a solar vendor organization. In March 2008, the PUC approved a stipulated agreement filed by the parties (except for KIUC, which has its own stipulated agreement) to increase the maximum size of the eligible customer-generators from 50 kw to 100 kw and the system cap from 0.5% to 1.0% of system peak demand, to reserve a certain percentage of the 1.0% system peak demand for generators 10 kw or less and to consider in the

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

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

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

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

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

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

Greenhouse gas emissions reduction . In July 2007, Act 234 became law, which requires a statewide reduction of greenhouse gas (GHG) emissions by January 1, 2020 to levels at or below the statewide GHG emission levels in 1990. It also establishes a task force, comprised of representatives of state government, business (including the electric utilities), the University of Hawaii and environmental groups, which is charged with preparing a work plan and regulatory approach for “implementing the maximum practically and technically feasible and cost-effective reductions in greenhouse gas emissions from sources or categories of sources of greenhouse gases” to achieve 1990 statewide GHG emission levels. The electric utilities are participating in the Task Force, as well as in initiatives aimed at reducing their GHG emissions, such as those to be undertaken under the Energy Agreement. Because the full scope of the Task Force report remains to be determined and regulations implementing Act 234 have not yet been promulgated, management cannot predict the impact of Act 234 on the electric utilities and the Company.

On April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts v. EPA, that, contrary to the EPA’s position, the EPA has the authority to regulate greenhouse gases under the Clean Air Act. Since then, the EPA has denied a California request for a waiver under the Clean Air Act to allow control of greenhouse gas emissions from motor vehicles, but has announced its intention to commence rulemaking to address greenhouse gas emissions. Although several bills addressing greenhouse gas emission reductions also have been introduced in Congress, none has yet been adopted. Accordingly, it is too early to assess the ultimate impact of the ruling.

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

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

Renewable energy . In 2007, a law was enacted that stated that the PUC may consider the need for increased renewable energy in rendering decisions on utility matters. Due to this measure, it is possible that, if energy from a renewable source were more expensive than energy from fossil fuel, the PUC may still approve the purchase of energy from the renewable source.

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

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

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

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

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

Other developments

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

Commitments and contingencies

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

Recent accounting pronouncements and interpretations

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

FINANCIAL CONDITION

Liquidity and capital resources

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

HECO’s consolidated capital structure was as follows as of the dates indicated:


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

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

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


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

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

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

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

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

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


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

Line of credit facility (expiring March 31, 2011) ¹				175		175
Undrawn capacity under line of credit facility ²				175		175

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

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

In the future, HECO may seek to modify the credit facility in accordance with the expedited approval process approved by the PUC, including to increase the amount of credit available under the agreement, and/or to enter into new lines of credit, as management deems appropriate. HECO is currently negotiating a new short-term syndicated credit facility, however, management cannot predict the timing and/or ultimate outcome of the negotiations.

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

HECO utilizes short-term debt, principally commercial paper, to support normal operations and for other temporary requirements. HECO also periodically borrows short-term from HEI for itself and on behalf of HELCO and MECO, and HECO may borrow from or loan to HELCO and MECO short-term. Management believes that, if HECO’s commercial paper ratings were to be downgraded or if credit markets further tighten, it would be more difficult and expensive to sell commercial paper or it might not be able to sell commercial paper in the future.

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

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

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

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

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

BANK

RESULTS OF OPERATIONS


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

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

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

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

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

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

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

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

Net interest margin and other factors

Earnings of ASB depend primarily on net interest income, which is the difference between interest earned on earning assets and interest paid on costing liabilities. The current interest rate environment is very volatile due to disruptions in the financial markets and may have a negative impact on ASB’s net interest margin.

Loan originations and purchases of loans and mortgage-related securities are ASB’s primary sources of earning assets. ASB’s loan volumes and yields are affected by market interest rates, competition, demand for financing, availability of funds and management’s responses to these factors. As of September 30, 2008, ASB’s loan portfolio mix, net, consisted of 72% residential loans, 13% commercial loans, 7% commercial real estate loans and 8% consumer loans. As of December 31, 2007, ASB’s loan portfolio mix, net, consisted of 75% residential loans, 11% commercial loans, 7% commercial real estate loans and 7% consumer loans. As of September 30, 2008, ASB-originated residential loans represented approximately 94% of the residential loan portfolio. All of the ASB-originated residential loans are located in the state of Hawaii, with approximately 66% of the loans located on the island of Oahu. At origination, approximately 70% of the ASB-originated loans had FICO scores greater than 700 and over 70% of the ASB-originated loans had loan-to-values less than or equal to 80%. ASB’s mortgage-related securities portfolio consists primarily of shorter-duration assets and is affected by market interest rates and demand.

Deposits continue to be the largest source of funds for ASB and are affected by market interest rates, competition and management’s responses to these factors. Advances from the FHLB of Seattle and securities sold under agreements to repurchase continue to be significant sources of funds. As of September 30, 2008, ASB’s costing liabilities consisted of 86% deposits and 14% other borrowings. As of December 31, 2007, ASB’s costing liabilities consisted of 71% deposits and 29% other borrowings. The decrease in the relative level of other borrowings and corresponding increase in the level of deposits was due to the early extinguishment of certain borrowings through the restructuring of ASB’s balance sheet. (See “Balance sheet restructure” in Note 4 of HEI’s Notes to Consolidated Financial Statements.) Competition for deposits and the level of short-term interest rates have made it difficult to retain deposits and control funding costs. Deposit retention and growth will remain a challenge in the current environment.

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

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

Although higher long-term interest rates or other conditions in credit markets (such as the effects of the deteriorated subprime market) could reduce the market value of available-for-sale investment and mortgage-related securities and reduce stockholder’s equity through a balance sheet charge to AOCI, this reduction in the market value of investments and mortgage-related securities would not result in a charge to net income in the absence of a sale of such securities (such as those that occurred in the balance sheet restructure) or an “other-than-temporary” impairment in the value of the securities. As of September 30, 2008 and December 31, 2007, the unrealized losses, net of tax benefits, on available-for-sale investments and mortgage-related securities (including securities pledged for repurchase agreements) in AOCI was $10 million and $18 million, respectively. See “Quantitative and qualitative disclosures about market risk.”

Average Balance Sheet and Net Interest Margin

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


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

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

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

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

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

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

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

Net interest income				$	52,312					$	47,690

Net interest margin (%) ³						4.08						2.97


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

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

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

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

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

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

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

Net interest income				$	155,451					$	148,100

Net interest margin (%) ³						3.49						3.05

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

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

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

Results – three months ended September 30, 2008

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

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

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

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

Results – nine months ended September 30, 2008

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

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


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

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

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

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

Nonaccrual loans		10,036			8,385			3,195

Nonperforming assets to total assets		0.19	%		0.12	%		0.05	%

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

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

FINANCIAL CONDITION

Liquidity and capital resources


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

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

In March 2007, Moody’s raised ASB’s counterparty credit rating to A3 from Baa3 and, in August 2008, maintained the rating following its annual review of ASB. In April 2007, S&P raised ASB’s long-term/short-term counterparty credit ratings to BBB/A-2 from BBB-/A-3 and in May 2008 maintained the rating following its annual review of ASB. These ratings reflect only the view, at the time the ratings are issued, of the applicable rating agency, from whom an explanation of the significance of such ratings may be obtained. Such ratings are not recommendations to buy, sell or hold any securities; such ratings may be subject to revision or withdrawal at any time by the rating agencies; and each rating should be evaluated independently of any other rating.

As of September 30, 2008, ASB’s unused FHLB borrowing capacity was approximately $1.4 billion. As of September 30, 2008, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.3 billion. Management believes ASB’s current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.

For the first nine months of 2008, net cash provided by ASB’s operating activities was $29 million. Net cash provided during the same period by ASB’s investing activities was $1.3 billion, primarily due to proceeds from the

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

As of September 30, 2008, ASB was well-capitalized (minimum ratio requirements noted in parentheses) with a leverage ratio of 8.4% (5.0%), a Tier-1 risk-based capital ratio of 12.2% (6.0%) and a total risk-based capital ratio of 13.1% (10.0%).

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Company considers interest-rate risk (a non-trading market risk) to be a very significant market risk for ASB as it could potentially have a significant effect on the Company’s financial condition and results of operations. For additional quantitative and qualitative information about the Company’s market risks, see pages 50 to 52, HEI’s Quantitative and qualitative disclosures about market risk, which is incorporated into Part II, Item 7A of HEI’s 2007 Form 10-K by reference to HEI Exhibit 13 to HEI’s Current Report on Form 8-K dated February 21, 2008.

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


	September 30, 2008						December 31, 2007
	Change in NII		NPV ratio		NPV ratio sensitivity *		Change in NII		NPV ratio		NPV ratio sensitivity *
Change in interest rates (basis points)	Gradual change		Instantaneous change				Gradual change		Instantaneous change
+300	(0.8	)%	8.10	%	(454	)	(2.2	)%	6.97	%	(334	)
+200	(0.5	)	9.65		(299	)	(0.9	)	8.27		(204	)
+100	(0.2	)	11.22		(142	)	(0.2	)	9.46		(85	)
Base	—		12.64		—		—		10.31		—
-100	(0.6	)	13.49		85		(0.5	)	10.40		9
-200	**		**		**		(3.0	)	9.67		(64	)
-300	**		**		**		(6.9	)	8.68		(163	)

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

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

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

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

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

The computation of the prospective effects of hypothetical interest rate changes on the NII sensitivity, NPV ratio, and NPV ratio sensitivity analyses is based on numerous assumptions, including relative levels of market interest rates, loan prepayments, balance changes and pricing strategies, and should not be relied upon as indicative of actual results (see page 51 of HEI Exhibit 13 to HEI’s Current Report on Form 8-K dated February 21, 2008 for a more detailed description of key modeling assumptions used in the NII sensitivity analysis). To the extent market conditions and other factors vary from the assumptions used in the simulation analysis, actual results may differ materially from the simulation results. Furthermore, NII sensitivity analysis measures the change

in ASB’s twelve-month, pre-tax NII in alternate interest rate scenarios, and is intended to help management identify potential exposures in ASB’s current balance sheet and formulate appropriate strategies for managing interest rate risk. The simulation does not contemplate any actions that ASB management might undertake in response to changes in interest rates. Further, the changes in NII vary in the twelve-month simulation period and are not necessarily evenly distributed over the period. These analyses are for analytical purposes only and do not represent management’s views of future market movements, the level of future earnings, or the timing of any changes in earnings within the twelve month analysis horizon. The actual impact of changes in interest rates on NII will depend on the magnitude and speed with which rates change, actual changes in ASB’s balance sheet, and management’s responses to the changes in interest rates.

Item 4. Controls and Procedures

HEI:

Changes in Internal Control over Financial Reporting

During the third quarter of 2008, there was no change in internal control over financial reporting identified in connection with management’s evaluation of the effectiveness of the Company’s internal control over financial reporting as of September 30, 2008 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Constance H. Lau, HEI Chief Executive Officer, and Curtis Y. Harada, HEI Chief Financial Officer, have evaluated the disclosure controls and procedures of HEI as of September 30, 2008. Based on their evaluations, as of September 30, 2008, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective in ensuring that information required to be disclosed by HEI in reports HEI files or submits under the Securities Exchange Act of 1934:

(1)

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

(2)

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

HECO:

Changes in Internal Control over Financial Reporting

During the third quarter of 2008, there was no change in internal control over financial reporting identified in connection with management’s evaluation of the effectiveness of HECO and its subsidiaries’ internal control over financial reporting as of September 30, 2008 that has materially affected, or is reasonably likely to materially affect, HECO and its subsidiaries’ internal control over financial reporting.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Constance H. Lau, HECO Principal Executive Officer, and Tayne S. Y. Sekimura, HECO Chief Financial Officer, have evaluated the disclosure controls and procedures of HECO as of September 30, 2008. Based on their evaluations, as of September 30, 2008, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective in ensuring that information required to be disclosed by HECO in reports HECO files or submits under the Securities Exchange Act of 1934:

(1)

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

(2)

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

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

The descriptions of legal proceedings (including judicial proceedings and proceedings before the PUC and environmental and other administrative agencies) in HEI’s Form 10-K (see “Part I. Item 3. Legal Proceedings,” “Part III, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part III, Item 8. Financial Statements and Supplementary Data”) and this 10-Q (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and HECO’s “Notes to Consolidated Financial Statements”) are incorporated by reference in this Item 1. With regard to any pending legal proceeding, alternative dispute resolution, such as mediation or settlement, may be pursued where appropriate, with such efforts typically maintained in confidence unless and until a resolution is achieved. Certain HEI subsidiaries (including HECO and its subsidiaries and ASB) may also be involved in ordinary routine PUC proceedings, environmental proceedings and litigation incidental to their respective businesses.

Item 1A. Risk Factors

For information about Risk Factors, see pages 30 to 39 of HEI’s 2007 Form 10-K, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Quantitative and Qualitative Disclosures about Market Risk,” HEI’s Consolidated Financial Statements and HECO’s Consolidated Financial Statements herein. Also, see “Forward-Looking Statements” on page v of HEI’s 2007 Form 10-K, as updated on pages iv and v herein.

The following risk factor has been updated:

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

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

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

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

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

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

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

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

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

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

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

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

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

(a) For the nine months ended September 30, 2008, HEI issued an aggregate of 31,600 shares of unregistered common stock pursuant to the HEI 1990 Nonemployee Director Stock Plan, as amended and restated effective May 6, 2008 (the HEI Nonemployee Director Plan). Under the HEI Nonemployee Director Plan, each HEI nonemployee director receives, in addition to an annual cash retainer, an annual stock grant of 1,800 shares of HEI common stock (2,000 shares for the first time grant to a new HEI director) and each nonemployee subsidiary director who is not also an HEI nonemployee director receives an annual stock grant of 1,000 shares of HEI common stock (1,000 shares for the first time grant to a new subsidiary director). The HEI Nonemployee Director Plan is currently the only plan for nonemployee directors and provides for annual stock grants (described above) and annual cash retainers for nonemployee directors of HEI and its subsidiaries.

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

Item 5. Other Information

A. Ratio of earnings to fixed charges .


	Nine months ended September 30		Years ended December 31
	2008	2007	2007	2006	2005	2004	2003
HEI and Subsidiaries
Excluding interest on ASB deposits	2.11	1.53	1.78	2.08	2.31	2.32	2.11
Including interest on ASB deposits	1.76	1.35	1.52	1.73	1.98	2.00	1.84
HECO and Subsidiaries	3.83	1.84	2.43	3.14	3.23	3.49	3.36

See HEI Exhibit 12.1 and HECO Exhibit 12.2.

B. News release .

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

C. Assignment of participation interest in Credit Agreement .

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

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

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

E. Amended Plans .

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

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

F. HECO Audit Committee Charte r

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

Item 6. Exhibits


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

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

HEI Exhibit 10.2		HEI Executives’ Deferred Compensation Plan

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

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



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

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

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

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

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

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

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

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

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

HEI Exhibit 99.1		News release, dated November 4, 2008, “Hawaiian Electric Industries, Inc. Reports Solid Third Quarter 2008 Results”

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

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

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

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

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

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

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

HECO Exhibit 32.3		Written Statement of Constance H. Lau (HECO Principal Executive Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002

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

SIGNATURES

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


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

By	/s/ Constance H. Lau	By	/s/ Constance H. Lau
	Constance H. Lau		Constance H. Lau
	President and Chief Executive Officer		Chairman of the Board
	(Principal Executive Officer of HEI)		(Principal Executive Officer of HECO)

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

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

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

HEI Exhibit 3(ii)

AMENDED AND RESTATED BYLAWS

HAWAIIAN ELECTRIC INDUSTRIES, INC.

As last amended October 31, 2008

ARTICLE I

NAME AND SEAL

Section 1. The name of the corporation shall be

HAWAIIAN ELECTRIC INDUSTRIES, INC.

Section 2. The seal of the corporation shall be in such form as the board of directors shall determine from time to time.

ARTICLE II

SHAREHOLDERS

Section 1. Each meeting of the shareholders shall be held at the principal office of the corporation in Honolulu, Hawaii, unless some other place in Honolulu is stated in the notice of meeting.

Section 2. The annual meeting of the shareholders shall be held on such date and time as the board of directors or, if it does not act, the chairman of the board of directors, or in the chairman’s absence or disability, the president may designate in each year. At the annual meeting the shareholders shall elect the directors to hold office until the next annual meeting at which they are to be elected or until their successors shall be duly elected and qualified, shall vote on the ratification of the appointment of the corporation’s independent registered public accounting firm and may transact any general business as is properly brought before the meeting in accordance with these Bylaws. Failure to hold an annual meeting at a time fixed in accordance with these Bylaws does not affect the validity of any corporate action.

No business may be transacted at the annual meeting of shareholders, other than business that is either (i) specified in the notice of meeting (or any supplement thereto) given by or at the direction of the board of directors (or any duly authorized committee thereof), (ii) otherwise properly brought before the annual meeting by or at the direction of the board of directors (or any duly authorized committee thereof) or (iii) otherwise properly brought before the annual meeting by any shareholder of the corporation (a) who is a shareholder of record on the date of the giving of the notice provided for in this Section 2 and on the record date for the determination of shareholders entitled to vote at such annual meeting and (b) who complies with the notice procedures set forth in this Section 2. In addition to any other applicable requirements, for business to be properly brought before an annual meeting by a shareholder, such shareholder must have given timely notice thereof in proper written form to the secretary of the corporation, which notice is not withdrawn by such shareholder at or prior to such annual meeting.

To be timely, a shareholder’s notice to the secretary must be delivered to or mailed and received at the principal executive offices of the corporation not less than sixty (60) days nor more than ninety (90) days prior to the anniversary date of the immediately preceding annual meeting of shareholders; provided, however, that in the event that the annual meeting is called for a date that is not within thirty (30) days before or after such anniversary date, notice by the shareholder in order to be timely must be so received not later than the close of business on the tenth (10th) day following the day on which notice of the date of the annual meeting was mailed or public disclosure of the date of the annual meeting was made, whichever first occurs.

To be in proper written form, a shareholder’s notice to the secretary must set forth as to each matter such shareholder proposes to bring before the annual meeting (i) a brief description of the business desired to be brought before the annual meeting and the reasons for conducting such business at the annual meeting, (ii) the name and record address of such shareholder, (iii) the class and number of shares of capital stock of the corporation which are owned beneficially or of record by such shareholder, (iv) a description of all arrangements or understandings between such shareholder and any other person or persons (including their names) in connection with the proposal of such business by such shareholder and any material interest of such shareholder in such business and (v) a representation that such shareholder intends to appear in person or by proxy at the annual meeting to bring such business before the meeting.

No business shall be conducted at the annual meeting of shareholders except business brought before the annual meeting in accordance with the procedures set forth in this Section 2; provided, however, that, once business has been properly brought before the annual meeting in accordance with such procedures, nothing in this Section 2 shall be deemed to preclude discussion by any shareholder of any such business. If the chairman of the board of directors, the president or other person presiding at the annual meeting, as the case may be, determines that business was not properly brought before the annual meeting in accordance with the foregoing procedures, the chairman, president or such other person shall declare to the meeting that the business was not properly brought before the meeting and such business shall not be transacted.

Section 3. Special meetings of shareholders shall be called by the secretary at any time upon request of the board of directors, the chairman of the board of directors or the president or upon the written demand of shareholders entitled to make such demand in the manner prescribed by law. At any special meeting only business within the purpose or purposes described in the notice of such meeting shall be conducted.

Section 4. Notices of all shareholders’ meetings shall specify the class or classes of stock entitled to vote at such meeting, the place, day and hour of the meeting and whether the meeting is annual or special. Notices of special meetings of shareholders must include a description of the purpose or purposes for which the meeting is called. Notice of each meeting of shareholders shall be given to each shareholder of record entitled to vote at such meeting at least ten (10) days but not more than sixty (60) days before the date set for such meeting, either (i) by mailing the same, postage prepaid or (ii) by electronic transmission to the facsimile number or electronic mail address to which the shareholder has previously consented (and not revoked its consent) to receive notice, in either event such notice shall be addressed to each shareholder at

the shareholder’s address as it appears upon the books of the corporation, in which case such mailing or electronic transmission shall constitute sufficient notice to shareholders. Non-receipt of any such notice shall not invalidate any business done at any meeting at which a quorum shall be present.

Section 5. Any meeting of the shareholders may be adjourned from time to time, whether or not a quorum is present, to reconvene at the same or some other place, and notice need not be given of any such adjourned meeting if the time and place thereof are announced at the meeting at which the adjournment is taken. At the adjourned meeting, the corporation may transact any business which might have been transacted at the original meeting. If the adjournment is for more than one hundred and twenty days (120) after the date fixed for the original meeting, a new record date shall be fixed for the adjourned meeting and notice of the adjourned meeting in accordance with the requirements of Section 4 of this Article II shall be given to each shareholder of record entitled to notice of and to vote at the meeting.

Section 6. Subject to the provisions set forth below, the holders of a majority of the shares of capital stock of the corporation outstanding and entitled to vote, present in person or by proxy at any meeting of shareholders, shall constitute a quorum for the transaction of business, and, if a quorum is present, directors shall be elected by a plurality of the votes cast by the shares entitled to vote in the election at the meeting and action on matters other than the election of directors shall be taken if the votes cast favoring the action exceed the votes cast opposing the action. Once a share is represented for any purpose at a meeting it is deemed present for quorum purpose for the remainder of the meeting and for any adjournment of that meeting unless a new record date is or must be set for the adjourned meeting.

Each share of common stock shall be entitled to one vote, subject, however, to such limitation or loss of right as may be provided in resolutions which may be adopted from time to time creating issues of preferred stock or otherwise.

Whenever shares of preferred stock shall be outstanding and the holders of such shares shall be entitled to vote, each share of preferred stock shall be entitled to one vote unless the resolution creating the issue of preferred stock shall otherwise provide. Where shares of preferred stock shall be outstanding and shall be entitled to vote and the holders of common stock likewise entitled to vote, each share of common stock outstanding shall count as one vote (unless the resolution creating the issue of preferred stock shall otherwise provide) and each share of preferred stock outstanding shall count as one vote in determining the presence or absence at any meeting of a majority of outstanding shares and in determining whether the holders of a specific proportion of the capital stock outstanding have approved or disapproved of any action.

If any class of stock of the corporation shall by the terms of its issuance be not entitled to vote or if any class of stock by virtue of any resolution authorizing the issuance of preferred stock loses its right to vote, then such stock shall not be counted as a part of the issued and outstanding stock of the corporation for the purpose of determining the presence or absence of a quorum at any meeting or whether or not the holders of a specified proportion of the capital stock outstanding have approved or disapproved of any action.

Whenever pursuant to the provisions of the resolutions authorizing the issuance of shares of preferred stock the holders of the preferred stock shall vote as a class and the holders of the common stock shall vote as a class, the holders of a majority of the shares of each class outstanding shall constitute a quorum with respect to the voting of such class. Subject to the other provisions of this Section 6, if a quorum of the class is present, action on matters other than the election of directors is taken by the class if the votes cast within the class favoring the action exceed the votes cast opposing the action.

The provisions of this Section 6 of Article II are subject to any provisions of law or of the Articles of Incorporation or any resolution authorizing the issuance of shares of preferred stock or of these Bylaws requiring with respect to any matters the approval or consent of designated percentages of the outstanding shares of stock or of the outstanding shares of any class thereof, or limiting or restricting the right of any class or classes of stock to vote with respect to any matters.

Section 7. Before any person is entitled to attend a meeting or vote any stock of the corporation, either as a shareholder or as the representative of a shareholder, at the secretary’s discretion, the secretary may require such reasonable evidence as to the identity or the authority of such person to attend the meeting and vote the stock of the corporation as the secretary may deem advisable.

A shareholder may vote the shareholder’s shares in person or by proxy. A shareholder may appoint a proxy to vote or otherwise act on the shareholder’s behalf by signing an appointment form; provided that, if two or more persons are named as proxies by or on behalf of the same shareholder, then at the sole discretion of the presiding officer of the meeting, the presiding officer may limit attendance at the meeting to one person so named. The appointment form must be signed by either the shareholder personally or by the shareholder’s attorney-in-fact. A shareholder may authorize another person to act as a proxy for the shareholder by: (i) executing a writing authorizing another person or persons to act as a proxy for the shareholder; which may be accomplished by the shareholder or the shareholder’s authorized attorney-in-fact, officer, director, employee or agent signing the writing or causing the shareholder’s signature to be affixed to the writing by any reasonable means, including, without limitation, the use of a facsimile signature, or (ii) transmitting or authorizing the transmission of a telegram, cablegram, facsimile, or other means of electronic transmission authorizing the person or persons to act as a proxy for the shareholder to the person or persons who will be the holder of the proxy or to a proxy solicitation firm, proxy support service organization, or similar agent duly authorized by the person who will be the holder of the proxy to receive the transmission; provided that any such transmission must specify that the transmission was authorized by the shareholder.

Any copy, facsimile telecommunication or other reliable reproduction of the writing or transmission created pursuant to the foregoing may be used in lieu of the original writing or transmission for any and all purposes for which the original writing or transmission could be used; provided, however, that such copy, facsimile telecommunication or other reproduction shall be a complete reproduction of the entire original writing or transmission.

An appointment of a proxy is effective when received by the secretary or other officer or agent authorized to tabulate votes. Any proxy authorization given pursuant to this section shall be valid and effective until written revocation thereof is filed with the corporation, provided that no appointment is valid for more than eleven (11) months unless a longer period is expressly provided for in the appointment form. If any shareholder who has given a proxy is present at a meeting of shareholders, such proxy shall remain in effect unless the shareholder revokes the proxy by voting in person at the meeting.

Section 8. An executor, administrator, guardian or trustee may vote in person or by proxy at any meeting of the corporation the stock of the corporation held by that person in such capacity, whether or not such stock shall have been transferred to that person’s name on the books of the corporation. In case the stock shall not have been so transferred to that person’s name on the books of the corporation that person shall, as a prerequisite to so voting, file with or present to the corporation a certified copy of that person’s letters as such executor, administrator or guardian, or that person’s appointment or authority as trustee. In case there are two or more executors, administrators, guardians or trustees, all or a majority of them may vote the stock in person or by proxy at any meeting of the corporation. If the name signed on a vote, consent, waiver or proxy appointment does not correspond to the name of the shareholder, the corporation may nevertheless, to the extent permitted by law, accept the vote, consent, waiver or proxy appointment and give it effect as the act of the shareholder.

Section 9. The duly authorized representative of another corporation owning stock in the corporation or having authority to vote stock of another shareholder of the corporation shall be entitled to vote the stock so owned or represented.

Section 10. The shareholders having voting rights who shall be entitled to vote at any meeting of shareholders may be determined by Section 2 of Article XVII of these Bylaws.

Section 11. Whenever the corporation shall have a class of equity securities registered pursuant to the Exchange Act which are listed on a national securities exchange or traded over-the-counter on a national securities market of the National Association of Securities Dealers, Inc. Automated Quotation System, no holder of shares of any class of capital stock of the corporation shall be entitled to cumulate votes in the election of directors.

Section 12. After fixing a record date for a meeting of shareholders, the corporation shall prepare an alphabetical list of the names of all shareholders who are entitled to notice of the meeting. The list shall be arranged by voting group (and within each voting group by class or series of shares) and show the address of and number of shares held by each shareholder.

The shareholders list shall be available for inspection by any shareholder, beginning two business days after notice of the meeting for which the list was prepared is given and continuing through the meeting, at the corporation’s principal office or at a place identified in the meeting notice in the city where the meeting will be held, or on a reasonably accessible electronic network (provided that all the information required to gain access to the shareholders’ list is provided with the meeting notice and the corporation takes reasonable steps to ensure that

such information is available only to shareholders of the corporation). A shareholder or shareholder’s agent or attorney shall be entitled, on written demand, to inspect and copy the shareholders list during regular business hours and at the shareholder’s expense during the period it is available for inspection. The shareholders list shall also be available at the meeting, and any shareholder or shareholder’s agent or attorney is entitled to inspect and to copy the list during the meeting or any adjournment. Refusal or failure to prepare or make available the shareholders list does not affect the validity of action taken at the meeting.

ARTICLE III

BOARD OF DIRECTORS

Section 1. There shall be a board of directors to consist of not less than five (5) nor more than eighteen (18) members, who need not be shareholders, the exact number of directors to be determined from time to time by resolution adopted by the affirmative vote of a majority of the entire board.

So long as there are at least nine directors, other than directors elected by the holders of preferred stock or any series of preferred stock voting separately as a class, the directors (other than the directors thus elected by holders of preferred stock) shall be divided into three classes, designated Class I, Class II and Class III. Each such class of such directors shall consist, as nearly as may be possible, of one-third of the total number of such directors constituting the entire board. Each such director shall serve for a term ending on the date of the third annual meeting of shareholders following the annual meeting at which the director was elected. Notwithstanding the foregoing, each director shall serve until his successor is duly elected and qualified, or until his retirement, death, resignation or removal. If the number of directors is changed, other than to change the number of directors to be elected by the holders of preferred stock or any series of preferred stock, voting separately as a class, any increase or decrease shall be apportioned among the classes so as to maintain the number of directors in each class as nearly equal as possible, and any additional director of any class elected to fill a vacancy resulting from an increase in such class shall hold office for a term that shall coincide with the remaining term of that class, but in no case will a decrease in the number of directors of any class of directors shorten the term of any incumbent director of any class of directors.

In the event holders of any preferred stock or any series of preferred stock are entitled to elect directors voting separately as a class or series, such holders shall be entitled to elect the number of directors provided for in the Articles of Incorporation or resolution authorizing the issuance of such stock subject to and upon the terms and conditions of such resolution, notwithstanding the number of directors fixed by the board of directors as provided for in this section of Article III.

Section 2. Only persons who are nominated in accordance with the following procedures shall be eligible for election as directors of the corporation, except as may be otherwise provided in the corporation’s Articles of Incorporation or resolution creating a series of preferred stock with respect to the rights of holders of preferred stock to nominate and elect a specified number of directors in certain circumstances. Nominations of persons for election to

the board of directors may be made at any annual meeting of shareholders, or at any special meeting of shareholders called for the purpose of electing directors, (i) by or at the direction of the board of directors (or any duly authorized committee thereof) or (ii) by any shareholder of the corporation (a) who is a shareholder of record on the date of the giving of the notice provided for in this Section 2 and on the record date for the determination of shareholders entitled to vote at such meeting and (b) who complies with the notice procedures set forth in this Section 2.

In addition to any other applicable requirements, for a nomination to be made by a shareholder, such shareholder must have given timely notice thereof in proper written form to the secretary of the corporation, which notice is not withdrawn by such shareholder at or prior to the meeting of shareholders.

To be timely, a shareholder’s notice to the secretary must be delivered to or mailed and received at the principal executive offices of the corporation (a) in the case of the annual meeting, not less than sixty (60) days nor more than ninety (90) days prior to the anniversary date of the immediately preceding annual meeting of shareholders; provided, however, that in the event that the annual meeting is called for a date that is not within thirty (30) days before or after such anniversary date, notice by the shareholder in order to be timely must be so received not later than the close of business on the tenth (10th) day following the day on which notice of the date of the annual meeting was mailed or public disclosure of the date of the annual meeting was made, whichever first occurs; and (b) in the case of a special meeting of shareholders called for the purpose of electing directors, not later than the close of business on the tenth (10th) day following the day on which notice of the date of the special meeting was mailed or public disclosure of the date of the special meeting was made, whichever first occurs.

To be in proper written form, a shareholder’s notice to the secretary must set forth (i) as to each person whom the shareholder proposes to nominate for election as a director (a) the name, age, business address and residence address of the person, (b) the principal occupation or employment of the person, (c) the number of shares of capital stock of the corporation which are owned beneficially or of record by the person and (d) any other information relating to the person that would be required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations of proxies for election of directors pursuant to Section 14 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the rules and regulations promulgated thereunder; and (ii) as to the shareholder giving the notice (a) the name and record address of such shareholder, (b) the number of shares of Capital Stock of the corporation which are owned beneficially or of record by such shareholder, (c) a description of all arrangements or understandings between such shareholder and each proposed nominee and any other person or persons (including their names) pursuant to which the nomination(s) are to be made by such shareholder, (d) a representation that such shareholder intends to appear in person or by proxy at the meeting to nominate the persons named in its notice and (e) any other information relating to such shareholder that would be required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations of proxies for election of directors pursuant to Section 14 of the Exchange Act and the rules and regulations promulgated thereunder. Such notice must be accompanied by a written consent of each proposed nominee to being named as a nominee and to serve as a director if elected.

No person shall be eligible for election as a director of the corporation unless nominated in accordance with the procedures set forth in this Section 2. If the chairman of the board of directors, the president or other person, as the case may be, presiding at the annual meeting determines that a nomination was not made in accordance with the foregoing procedures, the chairman, president or such other person shall declare to the meeting that the nomination was defective and such defective nomination shall be disregarded.

Section 3. Each meeting of the board of directors shall be held at the principal office of the corporation in Honolulu, Hawaii, unless some other place is stated in the notice of meeting. A meeting of the board of directors elected at an annual meeting of shareholders shall be held at the place of such annual meeting immediately or as soon as practicable thereafter, and no notice thereof shall be necessary.

Section 4. The board of directors may establish regular meetings which shall be held in such places, or by remote communication, and at such times as it may from time to time by vote determine, and when any such meeting or meetings shall be so determined no further notice thereof shall be required.

Section 5. Special meetings of the board of directors may be called at any time by the chairman of the board of directors, or by the president or by any two directors.

Section 6. Except as otherwise expressly provided, notice of any meeting of the board of directors for which notice is required to be provided shall be given to each director by the secretary or by the person calling the meeting, by advising the director by telephone, by word of mouth, by electronic transmission or by leaving written notice of such meeting with the director or at the director’s residence or usual place of business not later than the day before the meeting. Non-receipt of any such notice shall not invalidate any business done at any meeting at which a quorum is present. The presence or participation of any director at or in any meeting shall be the equivalent of a waiver of the requirement of the giving of notice of said meeting to such director, except where a director at the beginning of the meeting (or promptly upon such director’s arrival) objects to holding the meeting or to the transaction of any business and does not thereafter vote for or assent to action taken at the meeting. A director may, prior to, at or subsequent to the meeting, waive notice of the meeting in writing, signed by the director entitled to notice, and filed with the minutes or corporate records.

Section 7. A majority of the number of directors fixed in accordance with these Bylaws shall constitute a quorum for the transaction of business, except that a minority of the board may fill vacancies in the board as provided in Section 8 of this Article III. Unless the action of a greater number of directors shall be required by the Articles of Incorporation, these Bylaws, or law, the act of a majority of the directors present at a meeting at which a quorum is present shall be the act of the board of directors.

Section 8. In case of any vacancies due to death, incapacity, resignation or otherwise in the board of directors, the remaining members of the board of directors (although less than a majority thereof) may fill the same by the affirmative vote of a majority of such remaining members, subject, however, to the provisions of Section 9 of this Article III.

Section 9. The shareholders of the corporation may at any special meeting of the shareholders remove from office any director or directors ; provided that if a director was elected by a voting group of shareholders, only the shareholders of that voting group may participate in the vote to remove the director, and in the case of any such removal any vacancies on the board of directors arising from such removal which are not filled by the shareholders at such special meeting shall be filled by the remaining directors in accordance with the provisions of Section 8 of this Article III.

Section 10. The board of directors may create and appoint from its own membership such committees as it deems desirable, which shall have such functions and authority as the board of directors shall determine, subject to any limitations provided by law. Each committee must have two (2) or more members, who shall serve at the pleasure of the board of directors.

Section 11. Members of the board of directors or of a committee of the board of directors may participate in a meeting of such board or committee by means of conference telephone or similar communications equipment by means of which all persons participating in the meeting can hear each other at the same time, and participating in a meeting pursuant to this provision shall constitute presence in person at such meeting.

Section 12. Unless otherwise provided by law, any action required or permitted to be taken at any meeting of the board of directors, or of a committee of the board of directors, may be taken without a meeting, if all of the directors or all of the members of the committee, as the case may be, sign a written consent or written consents or provide consent via electronic transmission setting forth the action taken or to be taken, at any time before or after the intended effective date of such action. Such consent or consents shall be filed with the minutes of directors’ meetings or committee meetings, as the case may be, and shall have the same effect as a unanimous vote. In the case of consent by electronic transmission, the consent shall be submitted with information from which it may reasonably be concluded that the electronic transmission was authorized by the proper board or committee member.

Section 13. The only limitation on the power and authority of the board of directors to determine the number of directors is that there shall be not less than five (5) nor more than eighteen (18) members. There shall be no other limitations, whether numerical, based on percentage increase or decrease in the number of directors, or otherwise, on the power and authority of the board of directors to determine the number of directors.

ARTICLE IV

CHAIRMAN OF THE BOARD

There may be a chairman of the board of directors appointed from time to time by the board of directors from its own members. If the president is a director of the corporation the president may be appointed by the board of directors as the chairman of the board of directors. Whenever there shall be a chairman of the board of directors, the chairman shall preside at all meetings of the shareholders and of the board of directors, and shall have such powers and

perform such duties as may be assigned to the chairman of the board from time to time by the board of directors.

ARTICLE V

OFFICERS

The officers of the corporation shall be a president, one or more vice presidents, a treasurer, a controller, and a secretary. Any two of the offices of vice president, treasurer, controller and secretary may be held by the same person. There may also be such subordinate officers as the board of directors or the president shall appoint. Except as provided in Article XV, the officers shall be appointed annually by the board of directors at the first meeting thereof after the annual or special meeting of the shareholders at which the directors are elected, or as soon thereafter as practicable, and shall hold office until the first meeting of the board of directors following the next meeting of the shareholders at which the directors are elected and thereafter until their successors shall be duly appointed and qualified; provided, that the number of vice presidents may be changed from time to time by the board of directors at any meeting or meetings thereof and if increased at any time the additional vice president or vice presidents shall be appointed by the board of directors. No officer or subordinate officer need be a shareholder and no officer or subordinate officer need be a director of the corporation.

ARTICLE VI

PRESIDENT

If there shall be no chairman of the board of directors, or in the absence of the chairman of the board of directors, the president shall preside at meetings of the shareholders and of the board of directors. The president shall exercise general supervision and direction of the business and affairs of the corporation. The president shall, except as may otherwise be provided by resolution of the board of directors, have full authority to vote the shares of stock owned by the corporation at all meetings of other corporations in which the corporation may be a shareholder. The president shall have the powers and perform the duties customarily incidental to the office, and such other duties as may be given to the president elsewhere in these Bylaws or as may be assigned to the president from time to time by the board of directors.

ARTICLE VII

VICE PRESIDENTS

The vice presidents, in such order or according to such system as the board of directors shall determine or adopt, shall assume and perform the duties of the president when the office of president is vacant or whenever the president, for any reason, cannot discharge the duties of the office. The vice presidents of the corporation shall have such other powers and duties as may be given to them elsewhere in these Bylaws or as may be assigned to them from time to time by the board of directors or by the president.

ARTICLE VIII

TREASURER

The treasurer shall have the powers and perform the duties customarily incidental to the office and such other powers and duties as may be given to the treasurer elsewhere in these Bylaws or as may be assigned to the treasurer from time to time. In the absence or disability of the treasurer, or if that office is vacant, the treasurer’s duties may be performed by the controller, the secretary or by an assistant treasurer. The directors may by resolution authorize the controller, the secretary or an assistant treasurer equally with the treasurer to have any or all of the powers and to perform any or all of the duties given to the treasurer in these Bylaws.

ARTICLE IX

CONTROLLER

The controller shall have the powers and perform the duties customarily incidental to the office and such other powers and duties as may be given to the controller elsewhere in these Bylaws or as may be assigned to the controller from time to time. In the absence or disability of the controller, or if that office is vacant, the controller’s duties may be performed by the treasurer, secretary or by an assistant controller. The directors may by resolution authorize the treasurer, the secretary or an assistant controller equally with the controller to have any or all of the powers and to perform any or all of the duties given to the controller in these Bylaws.

ARTICLE X

SECRETARY

The secretary shall have the powers and perform the duties customarily incidental to the office. The secretary shall give notice of all meetings of the shareholders whenever requested to do so by the person thereunto duly authorized, shall prepare and maintain custody of the minutes of meetings of the shareholders and the board of directors, shall authenticate records of the corporation, and shall have such other powers and duties as may be given elsewhere in these Bylaws or as may be assigned to the secretary from time to time. In the absence or disability of the secretary, or if that office is vacant, the secretary’s duties may be performed by the treasurer, the controller or by an assistant secretary. The directors may by resolution authorize the treasurer, the controller or an assistant secretary equally with the secretary to have any or all of the powers and to perform any or all of the duties given to the secretary in these Bylaws.

ARTICLE XI

SUBORDINATE OFFICERS, AGENTS AND EMPLOYEES

Section 1. The board of directors or the president may appoint assistant vice presidents, assistant treasurers, assistant controllers, and assistant secretaries and such other subordinate officers and such agents as may be deemed proper, who shall hold their positions at the pleasure of the board of directors or the president, and who shall have such powers and duties as may be given elsewhere in these bylaws or as shall be determined by the board of directors or the president in the resolution or other documents evidencing the appointment. The president shall report to the board of directors the names and titles and powers (unless set forth elsewhere in these bylaws) of all subordinate officers appointed by the president. Any officer of the corporation may also be a subordinate officer, agent or employee.

Section 2. The salaries and compensation of all officers, subordinate officers and agents shall be determined by the board of directors. The authority to fix the salaries and compensation of subordinate officers and agents may be delegated by the board of directors to the president.

Section 3. The president shall have the control of all employees and shall determine the compensation of all employees other than that of the officers, subordinate officers and agents.

ARTICLE XII

ASSISTANT TREASURER

The assistant treasurer or assistant treasurers, if appointed, shall, in the order of priority of appointment, perform all of the duties and exercise all of the powers of the treasurer as directed by the treasurer, or during the absence or disability of the treasurer, or whenever the office is vacant, and shall perform all other duties as may be prescribed in writing by the president or the board of directors.

ARTICLE XIII

ASSISTANT CONTROLLER

The assistant controller or assistant controllers, if appointed, shall, in the order of priority of appointment, perform all of the duties and exercise all of the powers of the controller as directed by the controller, or during the absence or disability of the controller, or whenever the office is vacant, and shall perform all other duties as may be prescribed in writing by the president or the board of directors.

ARTICLE XIV

ASSISTANT SECRETARY

The assistant secretary or assistant secretaries, if appointed, shall, in the order of priority of appointment, perform all of the duties and exercise all of the powers of the secretary as directed by the secretary, or during the absence or disability of the secretary, or whenever the office is vacant, and shall perform all other duties as may be prescribed in writing by the president or the board of directors.

ARTICLE XV

REMOVALS AND VACANCIES

Section 1. The board of directors of the corporation may at any time remove from office or discharge from employment any officer, or subordinate officer, appointed by it or by any person under authority delegated by it, except insofar as such removal would be contrary to law.

Section 2. If the office of any officer, or subordinate officer, shall become vacant for any reason, the board of directors may appoint an acting or temporary officer or subordinate officer, or a successor in office, to serve at the pleasure of the board of directors; provided, however, that the president may appoint an acting or temporary subordinate officer, or a successor subordinate officer, to serve at the pleasure of the president or the board of directors.

ARTICLE XVI

SHARES OF CAPITAL STOCK

Section 1. Shares of the capital stock of the corporation may be certificated or uncertificated. Except as expressly provided by law, there shall be no differences in the rights and obligations of shareholders based on whether or not their shares are represented by certificates. The board of directors, by resolution, may authorize holders of the corporation’s shares to elect to hold their shares in certificated or uncertificated form. The authority to issue uncertificated shares shall not affect shares already represented by a certificate until the certificate is surrendered.

Section 2. In the case of certificated shares, certificates shall be in such form and device as the board of directors shall from time to time determine, provided that certificates shall plainly show at least the following information, together with any other information that may be required by law, rule or regulation, including the rules of any stock exchanges on which the shares are listed: (i) the certificate number and date of execution or issuance, (ii) the name of the corporation and that the corporation is organized under the laws of the State of Hawaii, (iii) the name of the person to whom the certificate has been issued or transferred, (iv) the number and class of shares, and the designation of the series, if any, the certificate represents, (v) a

summary of the designations, relative rights, preferences and limitations applicable to each class of stock or each series within a class of stock (and the authority of the board of directors to determine variations for future series), or a statement that the corporation will furnish this information without charge upon written request by the shareholder, (vi) a statement that the shares are without par value, (vii) if applicable, a statement as to the existence of any restrictions on transfer or registration of transfer of the shares and (viii) if applicable, a statement as to the existence of any additional rights or privileges incident to ownership of the shares. Each certificate of stock shall be sealed with the corporate seal and signed by the president or by a vice president and also by the secretary or an assistant secretary or by the treasurer or an assistant treasurer; provided, however, that the board of directors may provide that stock certificates which are manually signed by a transfer agent or by a registrar may be sealed with only the facsimile seal of the corporation and signed on behalf of the corporation with only the facsimile signatures of its officers and subordinate officers as above designated. In case any such officer who has signed or whose facsimile signature has been placed upon such certificate shall have ceased to be such officer before such certificate is issued, it may be issued by the corporation with the same effect as if such officer had not ceased to be such at the date of its issue.

Section 3. In the case of uncertificated shares, within a reasonable time after the issuance or transfer thereof, the corporation shall send the shareholder a written statement (which may be referred to as a transaction advice) containing at least the following information, together with any other information required by law, rule or regulation, including the rules of any stock exchanges on which the shares are listed: (i) the name of the corporation and that the corporation is organized under the laws of the State of Hawaii, (ii) the name of the person to whom the uncertificated shares have been issued or transferred, (iii) the number and class of shares, and the designation of the series, if any, to which the transaction advice relates, (iv) a summary of the designations, relative rights, preferences and limitations applicable to each class of stock or each series within a class of stock (and the authority of the board of directors to determine variations for future series), or a statement that the corporation will furnish this information without charge upon written request by the shareholder, (v) a statement that the shares are without par value, (vi) if applicable, a statement as to the existence of any restrictions on transfer or registration of transfer of the shares and (vii) if applicable, a statement as to the existence of any additional rights or privileges incident to ownership of the shares. The transaction advice shall also contain a statement to substantially the following effect: “This transaction advice is merely a confirmation of the share ownership of the addressee according to the stock records of the corporation as of the time of its issuance. Delivery of this transaction advice, by itself, confers no rights on the recipient. This transaction advice is neither a negotiable instrument nor a security.”

ARTICLE XVII

TRANSFER OF SHARES OF CAPITAL STOCK

Section 1. Transfers of shares of the capital stock of the corporation shall be made only by the corporation’s duly appointed secretary, transfer agent or registrar on the books of the corporation in accordance with the written instructions of the registered holder thereof, or by his or her duly authorized attorney-in-fact. No such transfer shall be valid, except between

the parties thereto, until such transfer shall have been recorded on the books of the corporation so as to show the date of the transfer, the names of the parties thereto, their addressees, and the number and description of the shares transferred. In the case of certificated shares, the transfer of shares of stock shall be made only upon surrender of the certificate or certificates representing such shares, properly endorsed or accompanied by a duly executed stock transfer power (with signature guarantee or such other satisfactory evidence or guarantee of authenticity and authority as the secretary, transfer agent or registrar may require) and the payment of all taxes thereon, and, if the transferred shares are to be certificated, the corporation shall issue one or more new certificates evidencing ownership of such shares by the new registered holder thereof. In the case of uncertificated shares, transfer of shares of stock on the records of the corporation shall be made only upon receipt of proper written or electronic transfer instructions from the registered owner or by his or her duly authorized attorney-in-fact or other authorized person (with signature guarantee or other satisfactory evidence or guarantee of authenticity and authority that the secretary, transfer agent or registrar may require) containing the following information: (i) the name, address and taxpayer identification number, if any, of the party transferring the shares, (ii) the number of shares transferred and the class of such shares, and the designation of the series, if any, and (iii) the name, address and taxpayer identification number, if any, of the party to whom the shares have been transferred and who, as a result of such transfer, is to become the new registered owner of the shares, and the payment of all taxes thereon. In the case of certificated shares or uncertificated shares that are to be transferred without certificates, such transfer shall be confirmed by the corporation’s sending of an appropriate transaction advice to the new registered holder thereof.

Section 2. The books for the transfer of stock may be closed as the board of directors may from time to time determine for a period not exceeding twenty (20) days before the annual or any special meeting of shareholders or before the day appointed for the payment of any dividend, or before any date on which rights of any kind in or in connection with the stock are to be determined or exercised; provided, however, that in lieu of closing the books for the transfer of stock the board of directors may fix in advance a day as the record date for determination of shareholders to be entitled to have or exercise the right to receive notice, to vote, to receive dividends, or to receive or exercise any such rights. In the event that the books for the transfer of stock are to be closed the secretary may be directed by the board of directors to give such notice of such closing as the board of directors may deem advisable.

Section 3. In case of the loss, mutilation or destruction of any certificate for any share or shares of stock of the corporation, a duplicate certificate may be issued upon such terms as the board of directors may prescribe, including but not limited to the requirement that the person requesting the duplicate certificate provide a bond or an agreement of indemnity acceptable to the corporation. In the event that the board of directors has authorized the issuance of shares of the relevant class or series of stock without certificates, a transaction advice or other written statement as described in Section 3 of Article XVI may be issued in place of any lost, mutilated or destroyed certificate theretofore issued by the corporation, upon such terms (including without limitation, the requirement of a bond or indemnity) as the board of directors may prescribe.

Section 4. The corporation shall be entitled to treat the holder of record of any share or shares of its capital stock as the holder in fact thereof for any and all purposes whatsoever and shall not be bound to recognize any equitable, beneficial ownership or other claim to or interest in such share or shares on the part of any other claimant thereto, whether or not it shall have express notice thereof, except as otherwise provided by law.

Section 5. The board of directors shall have power and authority to make all such rules and regulations as they deem expedient, concerning the issue, transfer and registration of shares of the capital stock of the corporation.

Section 6. Shares of its capital stock acquired by the corporation become authorized and unissued shares of the corporation and the acquisition of such shares by the corporation shall be evidenced by the cancellation of such shares in the stock records of the corporation.

ARTICLE XVIII

EXECUTION OF INSTRUMENTS

All checks, dividend warrants and other orders for the payment of money, drafts, notes, bonds, acceptances, contracts, and all other instruments, except as otherwise provided in these Bylaws, shall be signed by such person or persons as shall be provided by general or special resolution of the board of directors, and in the absence of any provision in these Bylaws or any such general or special resolution applicable to any such instrument then such instrument shall be signed by any two of the following: the president, any vice president, the treasurer, the controller or the secretary. The board of directors may delegate to any officer or officers of the corporation the power to designate the person or persons to execute any such instrument on behalf of the corporation. The board of directors may provide for the execution of any corporate instrument or document by electronic means, by a mechanical device or a machine, or by use of facsimile signatures, under such terms as shall be set forth in the resolution of the board of directors.

ARTICLE XIX

IMMUNITY AND INDEMNIFICATION

Immunity of directors and officers of the corporation and indemnification by the corporation of directors and officers of the corporation from costs and expenses and liabilities shall be governed by the provisions relating thereto included in the Articles of Incorporation of the corporation and in any indemnity agreements, as permitted by law, between the corporation and any such director or officer.

ARTICLE XX

FISCAL YEAR

The fiscal year of the corporation shall be the calendar year.

ARTICLE XXI

AMENDMENT TO BYLAWS

Section 1. These Bylaws may be altered, amended or repealed or new Bylaws enacted by the affirmative vote of a majority of the entire board of directors or at any regular meeting of the shareholders (or at any special meeting duly called for that purpose) by the affirmative vote of a majority of the shares represented and entitled to vote at such meeting (if notice of the proposed alteration or amendment or any new By-law provision or provisions is contained in the notice of such meeting); provided, however, that any provision for which a greater vote is required by the Articles of Incorporation, these Bylaws or by law, shall itself be amended only by such greater vote.

Section 2. Notwithstanding anything contained in Section 1 of this Article XXI to the contrary, either (i) the affirmative vote of the holders of at least 80 percent of the votes entitled to be cast by the holders of all shares of the corporation entitled to vote generally in the election of directors, voting together as a single class, or (ii) the affirmative vote of a majority of the entire board of directors with the concurring vote of a majority of the continuing directors, voting separately and as a subclass of directors, shall be required to alter, amend or repeal, or adopt any provision inconsistent with (a) the second paragraph of Section 2 of Article II relating to business properly brought before an annual meeting, (b) Section 3 of Article II, (c) Section 11 of Article II, (d) Section 1 of Article III, (e) Section 9 of Article III and (f) this Article XXI. For purposes of this Article XXI, the term “continuing director” shall mean any member of the board of directors who was a member of the board of directors on April 21, 1987 or who is elected to the board of directors after April 21, 1987, upon the recommendation of a majority of the continuing directors, voting separately and as a subclass of directors on such recommendation.

ARTICLE XXII

RIGHTS, OPTIONS AND WARRANTS

The corporation may issue, whether or not in connection with the issuance and sale of any of its stock or other securities, rights, options or warrants entitling the holders thereof to purchase from the corporation shares of any class or classes of stock. The board of directors shall determine the terms upon which the rights, options, or warrants are issued, their form and content, and the consideration for which the shares are to be issued. The documents evidencing such rights, options or warrants, may include conditions on the exercise of such rights, options or warrants, including conditions that preclude the holder or holders, including any subsequent transferees, of at least a specified percentage of the common shares of the corporation from exercising such rights, options or warrants.

* * *

HEI Exhibit 10.1

ASSIGNMENT AND ACCEPTANCE AGREEMENT

Assignment and Acceptance Agreement (as the same may be amended, supplemented or otherwise modified from time to time, this “Assignment and Acceptance Agreement” ), dated as of September 18, 2008 by and between Lehman Brothers Bank, FSB , a Lender under the Credit Agreement referred to below (the “Assignor” ), and Bank Hapoalim BM (the “Assignee” ).

R E C I T A L S

A. Reference is made to the Credit Agreement, dated as of March 31, 2006, among Hawaiian Electric Industries, Inc., a Hawaii corporation (the “ Borrower” ), the Lenders party thereto and The Bank of New York Mellon, formerly The Bank of New York, as Issuing Bank and Administrative Agent (as the same may be amended, supplemented or otherwise modified from time to time, the “Credit Agreement” ). Capitalized terms used herein which are not otherwise defined herein shall have the respective meanings ascribed thereto in the Credit Agreement.

B. Pursuant to the Credit Agreement and subject to the limitations set forth therein the Credit Parties agreed to make the Loans and participate in the Letter of Credit sub-facility under the terms and conditions therein set forth.

C. The amount of the Assignor’s Revolving Commitment and Letter of Credit Commitment (without giving effect to the assignment effected hereby or to other assignments thereof which have not yet become effective) is specified in Item 1 of Schedule 1 hereto. The outstanding principal amount of the Assignor’s Revolving Loans without giving effect to the assignment effected hereby or to other assignments thereof which have not yet become effective, is specified in Item 2 of Schedule 1 hereto.

D. The Assignor wishes to sell and assign to the Assignee, and the Assignee wishes to purchase and assume from the Assignor, (i) the portion of the Assignor’s rights and obligations under the Loan Documents, including its Revolving Commitment and Letter of Credit Commitment specified in Item 3 of Schedule 1 hereto (collectively, the “Assigned Commitment” ), and (ii) the portion of the Assignor’s Revolving Loans specified in Item 4 of Schedule 1 hereto (the “Assigned Loans” ). The parties agree as follows:

Assignment

Subject to the terms and conditions set forth herein and in the Credit Agreement, the Assignor hereby sells and assigns to the Assignee, and the Assignee hereby purchases and assumes from the Assignor, without recourse, on the date hereof, (i) all right, title and interest of the Assignor in and to the Assigned Loans, and (ii) all obligations of the Assignor under the Loan Documents with respect to the Assigned Commitment. As full consideration for the sale of the Assigned Loans, the Assignee shall

pay to the Assignor on the date hereof an amount equal to the principal amount of the Assigned Loans or such other amount as shall be agreed upon by the Assignor and the Assignee (the “Purchase Price” ), and the Assignor shall pay the fee payable to the Administrative Agent pursuant to Section 10.04(b) of the Credit Agreement.

Representations and Warranties

(a) Each of the Assignor and the Assignee represents and warrants to the other that (i) it has full power and legal right to execute and deliver this Assignment and Acceptance Agreement and to perform the provisions of this Assignment and Acceptance Agreement; (ii) the execution, delivery and performance of this Assignment and Acceptance Agreement have been authorized by all action, corporate or otherwise, and do not violate any provisions of its organizational documents or any contractual obligations or requirement of law binding on it; and (iii) this Assignment and Acceptance Agreement constitutes its legal, valid and binding obligation, enforceable against it in accordance with its terms. The Assignor further represents that it is the legal and beneficial owner of the interest being assigned by it hereunder and that such interest is free and clear of any adverse claim created by the Assignor.

(b) The Assignee represents and warrants to the Assignor (i) it is an “accredited investor” within the meaning of Regulation D of the Securities and Exchange Commission, as amended, and (ii) it has, independently and without reliance upon the Assignor, and based on such documents and information as it has deemed appropriate, made its own evaluation of, and investigation into, the business, operations, property, financial and other condition and creditworthiness of the Borrower and its Subsidiaries and made its own decision to enter into this Assignment and Acceptance Agreement.

Effect of Assignment.

(a) Upon the effective date hereof, (i) the Administrative Agent shall record the assignment contemplated hereby, (ii) the Assignee, unless already a Lender, shall become a Lender, with all the rights and obligations as a Lender under the Credit Agreement, and (iii) the Assignor, to the extent of the assignment provided for herein, shall be released from its obligations under the Loan Documents, with respect to the Assigned Loans and Assigned Commitments.

(b) The Assignee hereby appoints and authorizes the Administrative Agent to take such action, on and after the date hereof, as agent on its behalf and to exercise such powers under the Loan Documents as are delegated to such Administrative Agent by the terms thereof, together with such powers as are reasonably incidental thereto.

(c) From and after the effective date hereof, the Credit Parties and the Loan Parties shall make all payments in respect of the interest assigned hereby (including payments of principal, interest, fees and other amounts) to the Assignee. The Assignor and the Assignee shall make all appropriate adjustments directly between themselves

with respect to amounts under the Loan Documents which accrued prior to the date hereof and which were paid thereafter.

Method of Payment

All payments to be made either to the Assignor or the Assignee by the other hereunder shall be made by wire transfer in immediately available funds to the account designated by the Assignor or the Assignee, as the case may be.

Notices

All notices, requests and demands to or upon the Assignee in connection with this Assignment and Acceptance Agreement and the Loan Documents are to be sent or delivered to the place set forth adjacent to its name on the signature page(s) hereof.

Miscellaneous

(a) For purposes of this Assignment and Acceptance Agreement, all calculations and determinations with respect to the Assigned Loans, the Assigned Commitment and all other similar calculations and determinations, shall be made and shall be deemed to be made as of the commencement of business on the date of such calculation or determination, as the case may be.

(b) Section headings have been inserted herein for convenience only and shall not be construed to be a part hereof.

(c) This Assignment and Acceptance Agreement embodies the entire agreement and understanding between the Assignor and the Assignee with respect to the subject matter hereof and supersedes all other prior arrangements and understandings between the Assignor and the Assignee with respect to the subject matter hereof.

(d) This Assignment and Acceptance Agreement may be executed in any number of separate counterparts and all of said counterparts taken together shall be deemed to constitute one and the same agreement. It shall not be necessary in making proof of this Assignment and Acceptance Agreement to produce or account for more than one counterpart signed by the party to be charged.

(e) Every provision of this Assignment and Acceptance Agreement is intended to be severable, and if any term or provision hereof shall be invalid, illegal or unenforceable for any reason, the validity, legality and enforceability of the remaining provisions hereof shall not be affected or impaired thereby, and any invalidity, illegality or unenforceability in any jurisdiction shall not affect the validity, legality or enforceability of any such term or provision in any other jurisdiction.

(f) This Assignment and Acceptance Agreement shall be binding upon and inure to the benefit of the Assignor and the Assignee and their respective successors and

permitted assigns, except that neither party may assign or transfer any of its rights or obligations hereunder (i) without the prior written consent of the other party, and (ii) in contravention of the Credit Agreement.

(g) This Assignment and Acceptance Agreement and the rights and obligations of the parties hereunder shall be governed by, and construed and interpreted in accordance with, the law of the State of New York.

(h) This Assignment and Acceptance Agreement shall become effective on the date it has been executed by the Assignor, the Assignee, the Administrative Agent, if a Revolving Commitment is being assigned, the Issuing Bank and, unless an Event of Default has occurred and is continuing, the Borrower.

[Signature Pages To Follow]

IN WITNESS WHEREOF, the parties hereto have caused this Assignment and Acceptance Agreement to be duly executed and delivered by their proper and duly authorized officers as of the day and year first above written.


Lehman Brothers Bank, FSB, as Assignor

By:		/s/ Tina Chen
Name:		Tina Chen
Title:		Authorized Signatory


Bank Hapoalim BM , as Assignee

By:		/s/ Shaun Breidbart/Charles McLaughlin
Name:		Shaun Breidbart/Charles McLaughlin
Title:		Vice President/Senior Vice President

Consented to and Accepted this 18th day:

of September, 2008

THE BANK OF NEW YORK MELLON, as Administrative Agent and Issuing Bank


By:		/s/ Ronald R. Reedy
Name:		Ronald R. Reedy
Title:		Managing Director

Consented to this 16 ^th day:

of September, 2008

HAWAIIAN ELECTRIC INDUSTRIES, INC.


By:		/s/ Curtis Y. Harada
Name:		Curtis Y. Harada


By:		/s/ Chet A. Richardson
Name:		Chet A. Richardson

SCHEDULE 1

ASSIGNMENT AND ACCEPTANCE AGREEMENT,

dated as of September 18, 2008,

between Lehman Brothers Bank, FSB, as Assignor

and

Bank Hapoalim BM, as Assignee,

relating to the

Credit Agreement, dated as of March 31, 2006,

by and among

Hawaiian Electric Industries, Inc.,

the Lenders party thereto

and

The Bank of New York Mellon, formerly The Bank of New York , as Administrative Agent and Issuing Bank


Item 1.	*Amount of Assignor’s Aggregate Commitment :**

	(a) Revolving Commitment	$	5,454,545.45
	(b) Letter of Credit Commitment	$	2,727,272.73

Item 2.	Outstanding principal balance/amount of the Assignor’s Loans *:

	(a) Revolving Loans consisting of:
	ABR Borrowing	$	00.00
	Eurodollar Borrowing	$	00.00

Item 3.	Amount of Revolving Commitment and/or Letter of Credit Commitment being assigned:

	(a) Revolving Commitment	$	5,454,545.45
	(b) Letter of Credit Commitment	$	2,727,272.73

Item 4.	Outstanding principal balance/amount of the Revolving Loans being assigned:

	(a) Revolving Loans consisting of:
	ABR Borrowing	$	0.00
	Eurodollar Borrowing	$	0.00

HEI Exhibit 10.2

HAWAIIAN ELECTRIC INDUSTRIES, INC.

EXECUTIVES’ DEFERRED COMPENSATION PLAN

PREAMBLE

The following sets forth the terms of the Executives’ Deferred Compensation Plan of Hawaiian Electric Industries, Inc., as amended. This Plan is an unfunded deferred compensation arrangement solely for executives of the Company and the Participating Subsidiaries.

ARTICLE I

EFFECTIVE DATE AND CERTAIN DEFINITIONS

1.1 The original effective date of the Plan was February 1, 1985. The Plan was amended and restated in its entirety effective for elections made on or after January 1, 1990 and was again amended and restated effective for elections made with regard to services performed on or after January 1, 1991. The Plan as amended and restated herein is effective as of the Effective Date.

1.2 The following terms as used herein shall have the indicated meaning unless a different meaning is plainly required by the context. Whenever appropriate, words used in the singular may include the plural and vice versa.

“Committee” shall mean the Compensation Committee of the Board of Directors of the Company.

“Company” shall mean Hawaiian Electric Industries, Inc.

“Effective Date” shall mean January 1, 2009.

“Eligible Participant” shall have the meaning ascribed thereto in Article II of the Plan.

“Participating Subsidiaries” shall mean, collectively, Hawaiian Electric Company, Inc., Hawaii Electric Light Company, Inc. and Maui Electric Company, Limited.

“Plan” shall mean this Executives’ Deferred Compensation Plan of Hawaiian Electric Industries, Inc., as amended from time to time.

“Plan Administrator” shall mean the Vice President-Administration of the Company.

“Section 409A” shall mean Section 409A of the Internal Revenue Code of 1986, as amended.

ARTICLE II

ELIGIBILITY

Any executive who is employed by the Company or the Participating Subsidiaries and who is entitled to compensation under the HEI Executive Incentive Compensation Plan and/or the HEI Long-Term Incentive Plan (an “Eligible Participant”) shall be eligible to elect to participate in the Plan. The compensation earned under the HEI Executive Incentive Compensation Plan shall be referred to as the “annual incentive compensation award,” while the compensation earned under the HEI Long-Term Incentive Plan shall be referred to as the “long-term incentive compensation award.”

ARTICLE III

ELECTION TO PARTICIPATE IN THE PLAN

3.1 An Eligible Participant may at any time elect in writing on a form furnished by and filed with the Plan Administrator to participate in the Plan and thereby defer receipt of all or a specified portion of his or her annual and/or long-term incentive compensation award. The form for such election shall be substantially similar to the attached Form 1 or such other form as may be approved by the Plan Administrator. Once made, an election shall apply to all succeeding years unless revised or revoked pursuant to Section 3.3.

3.2 Such election shall be effective on the January 1 of the calendar year following the receipt of the election form by the Plan Administrator, with respect to any annual or long-term incentive compensation award earned during that calendar year and any succeeding year, except that an Eligible Participant who was not an Eligible Participant on the preceding December 31 may make an election, within 30 days of first becoming an Eligible Participant (or an eligible participant under any other plan that is aggregated with the Plan pursuant to Section 409A), to defer receipt of all or a specified portion of his or her annual and/or long-term incentive compensation award earned for the remainder of the calendar year (following submission of the election) in which he or she becomes an Eligible Participant (and succeeding calendar years, as applicable).

3.3 An Eligible Participant may at any time and from time to time in writing on a form furnished by and filed with the Plan Administrator change the terms of his or her election or terminate his or her participation in the Plan, effective as of the January 1 of the calendar year following the receipt of such form by the Plan Administrator with respect to any annual or long-term incentive compensation award earned on or after that effective date. Specimen forms for a revised election and for termination of participation are included, respectively, in the attached Forms 1 and 2, which Forms may be modified by the Plan Administrator, as he or she deems appropriate. However, all amounts deferred pursuant to the Plan prior to the effective date of such revised election or

(2)

termination shall continue to be subject to the terms of the prior election by the Eligible Participant in effect when such amounts were credited under the Plan or any subsequent further deferral by the Eligible Participant effected in accordance with Section 409A.

3.4 An Eligible Participant who terminates his or her participation in the Plan shall not be eligible to participate again in the Plan until the January 1 following the January 1 on which his or her termination of participation takes effect.

ARTICLE IV

ACCOUNTS

4.1 The Company shall maintain book accounts on behalf of each Eligible Participant who elects to participate in the Plan. The amounts of incentive compensation to be deferred under this Plan, if any, shall be credited to the applicable Eligible Participant’s account as of the date such incentive compensation otherwise would have been paid. The Company does not intend to set aside any cash or other assets to fund these accounts. Payments shall be made from the general funds of the Company when due under the terms of this Plan. Nothing contained in the Plan and no action pursuant to the provisions of the Plan shall be construed to create a trust of any kind.

4.2 Amounts credited to an Eligible Participant’s deferred compensation account shall be credited each year with an amount equivalent to interest, compounded quarterly, at the annual rate commensurate with the prevailing interest rate on three-year certificates of deposit at American Savings Bank, F.S.B., as of January 1 of that year; provided, however, that the balance of the Eligible Participant’s deferred compensation account as of December 31, 1990 shall be credited annually with interest at the rate of 2.5 percent (2.5%) per quarter, compounded quarterly. Such accrued interest shall be payable to the Eligible Participant at the same time as the deferred compensation is paid to the Eligible Participant.

4.3 Whether or not the Company sets aside any funds or invests any funds in contemplation of its obligations hereunder, all amounts deferred pursuant to the Plan (including deferred compensation and interest thereon) shall remain part of the general funds of the Company and no Eligible Participant shall acquire any property interest in his or her account, stock, or other assets of the Company, his or her right being limited to receiving from the Company deferred payments measured as set forth in this Plan. This right is conditioned upon continued compliance with the terms and conditions of this Plan. To the extent that any Eligible Participant acquires a right to receive benefits under this Plan, such right shall be no greater than the right of any unsecured general creditor of the Company.

(3)

4.4 Neither the account of, nor the right to receive payments under the Plan of, the Eligible Participant or his or her beneficiary shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, or encumbrance and such account or right may not be subject to the debts, contracts, liabilities, engagements or torts of the Eligible Director or his or her beneficiary.

ARTICLE V

DISTRIBUTIONS

5.1 (a) Amounts deferred under the Plan shall be distributed in accordance with the written, irrevocable election of the Eligible Participant on a form furnished and filed with the Plan Administrator as provided in Article III. The Eligible Participant shall indicate when such payments are to commence and the form of distribution.

(b) Payments under the Plan will commence on the first business day of the calendar year selected by the Eligible Participant, but payments must commence (1) not later than the first business day of the calendar year following the Eligible Participant’s attainment of age 72 and (2) subject to (1) above, not earlier than the first business day of the calendar year which is at least five (5) full years after the date of the Eligible Participant’s initial deferral election.

(c) (1) Payments, at the Eligible Participant’s election, shall either be in a lump sum or in substantially equal annual installments over a period of years not exceeding ten years.

(2) The amount of the installment payments shall be determined as follows. The total amount of deferred income (deferred compensation and interest thereon) in the Eligible Participant’s account as of the elected payment commencement date will be paid in equal annual payments over the number of years elected. Each annual payment, other than the first payment, shall include an additional amount equal to interest, compounded quarterly, at the rate specified in Section 4.2, compounded quarterly, on the amount in the Eligible Participant’s account as of the December 31 preceding such payment.

(d) Notwithstanding the foregoing provisions of this Section 5.1, in the case of any Participant who is a specified employee within the meaning of Section 409A upon his or her separation from service within the meaning of Section 409A, any payment that is made by reason of such separation from service shall commence not earlier than six months after such separation from service.

5.2 (a) Upon the death of an Eligible Participant or former Eligible Participant, prior to the expiration of the period during which the deferred amounts are payable, the balance of the deferred amounts will be paid on the first business day of the calendar year following the year of death in one lump-sum to such person or persons designated by the Eligible Participant or former Eligible Participant in

(4)

writing on a form furnished by and filed with the Plan Administrator. A specimen form for such beneficiary designation is included as part of Form 1, which Form may be modified by the Plan Administrator, as he or she deems appropriate. In the absence of such designation, the payment will be made to the Eligible Participant’s or former Eligible Participant’s estate.

(b) The amount payable on the first business day of the calendar year following an Eligible Participant’s or former Eligible Participant’s death shall be the dollar amount (deferred compensation plus interest) credited to his or her account as of the December 31 following his or her date of death.

5.3 In the event of an unforeseeable emergency (within the meaning of Section 409A) proven to the satisfaction of the Committee, an Eligible Participant or former Eligible Participant with an account under the Plan may receive an accelerated distribution of up to 50% of the amount credited to his or her account under the Plan, but not more than the amounts necessary to satisfy such emergency plus amounts necessary to pay taxes reasonably anticipated as a result of the distribution, after taking into account the extent to which such emergency is or may be relieved through reimbursement or compensation by insurance or otherwise or by liquidation of the Eligible Participant’s assets (to the extent the liquidation of such assets would not itself cause severe financial hardship).

5.4 Notwithstanding any other provision herein, neither the Plan nor the Company shall be obligated to make any payments hereunder unless and until all applicable requirements under federal, state and local laws have been fully met.

ARTICLE VI

AMENDMENT AND TERMINATION OF PLAN

6.1 The Plan may be amended from time to time by resolution of the Committee, but, except to the extent permitted under Section 409A, no such amendment shall permit amounts accumulated pursuant to the Plan prior to the amendment to be paid to an Eligible Participant prior to the time he or she would otherwise be entitled hereto.

6.2 The Plan will continue in effect until terminated by resolution of the Committee, but in the event of such termination, the amounts accumulated pursuant to the Plan prior to termination will continue to be subject to the provisions of the Plan as if the Plan had not been terminated.

ARTICLE VII

ADMINISTRATION OF THE PLAN

7.1 The Plan shall be administered by the Plan Administrator. The Plan Administrator shall have the power to delegate specific responsibilities to any

(5)

person or group of persons, and such person or group may serve in more than one such delegated capacity. Such delegations may be to employees of the Company or to other individuals, all of whom shall serve at the pleasure of the Plan Administrator and the Company, and if full-time employees of the Company or an affiliated company, without compensation. Any such person may resign by delivering a written resignation to the Plan Administrator. The Company shall pay all costs of administration of the Plan.

7.2 The Plan Administrator (or his or her delegate) has and may exercise such discretionary powers and authority as may be necessary or appropriate to carry out its functions under the Plan including, but not limited to, (i) deciding all questions that may arise under the Plan, (ii) interpreting the Plan and making all other determinations necessary or advisable for the administration of the Plan, and (iii) prescribing, amending and rescinding all rules and regulations to assure that the Plan complies with all applicable provisions of federal, state or local law. All interpretations, determination and actions by the Plan Administrator (or his or her delegate) shall be final, conclusive and binding on all parties.

ARTICLE VIII

MISCELLANEOUS

8.1 Nothing contained in the Plan shall be deemed to give any Eligible Participant a right to remain in the employment of the Company or a Participating Subsidiary.

8.2 If any person eligible to receive benefits under this Plan (a “payee”) is, in the opinion of the Plan Administrator, legally, physically, or mentally incapable of personally receiving and receipting for any payment under the Plan, the Plan Administrator may direct payments to such other person, persons, or institutions who, in the opinion of the Plan Administrator, are then maintaining or having custody of such payee, until claims are made by a duly appointed guardian or other legal representative of such payee. Such payments shall constitute a full discharge of the liability of the Plan to the extent thereof.

8.3 Except to the extent preempted by the Employee Retirement Income Security Act of 1974, as amended, the laws of the State of Hawaii shall govern and control the interpretation and application of the terms of the Plan.

8.4 All consents, elections, applications, designations, etc. required or permitted under the Plan must be made on forms prescribed and furnished by the Plan Administrator, and shall be recognized only if properly completed, executed, and returned to the Plan Administrator or his or her agent.

(6)

TO RECORD the adoption of this amended and restated Plan, Hawaiian Electric Industries, Inc. has caused this document to be executed this 28 day of October, 2008, effective as of January 1, 2009.


HAWAIIAN ELECTRIC INDUSTRIES, INC.

By		/s/ Patricia U. Wong
		Its Vice President-Administration & Corporate Secretary

(7)

HAWAIIAN ELECTRIC INDUSTRIES, INC.

EXECUTIVES’ DEFERRED COMPENSATION PLAN

FORM 1—INITIAL OR REVISED ELECTION FORM

Instructions: This form is used to make an initial deferred compensation contribution and distribution election or revise an existing contribution or distribution election and/or beneficiary designation. If this is an initial deferral election, please check the initial election box and complete A B, C and D. If you wish to revise a contribution election, please check the revised contribution election box and complete E. If you wish to revise a distribution election, please check the revised distribution election box and complete F and G. If you only wish to change your beneficiaries, please check the revised designation of beneficiary box and complete that section.

This election will apply to all future Executive Incentive Compensation Plan (EICP) and Long-Term Incentive Plan (LTIP) compensation unless you revise or terminate this election no later than December 31 of the year prior to the year you want the revised or terminated election to take effect.

I am an executive at:

¨ Hawaiian Electric Industries, Inc.

¨ Hawaiian Electric Company, Inc.

¨ Maui Electric Company, Limited

¨ Hawaii Electric Light Company, Inc.


Participant Name



Address



Social Security No.				Date of Birth

TO:

HAWAIIAN ELECTRIC INDUSTRIES, INC.

¨ INITIAL ELECTION (If this is an initial election, five years is the minimum deferral period provided that payments must commence not later than the first business day of the calendar year following your attainment of age 72.)

I hereby elect to participate in the Executives’ Deferred Compensation Plan (the “Plan”) of Hawaiian Electric Industries, Inc. (the “Company”) and agree to be bound by the terms and conditions of the Plan.

This election form relates to services rendered for plan years beginning January 1, .

I hereby elect to defer receipt of:

% of my annual incentive compensation.

% of my long-term incentive compensation.

% of my annual and long-term incentive compensation.

I hereby direct that such deferred amounts be paid in:

A lump sum.

Annual installments over a period of years (not more than 10 years).

I hereby direct that the distribution of such deferred amounts commence:


___		As of the first business day of the calendar year after I separate from service with the Company (within the meaning of Section 409A of the Internal Revenue Code of 1986, as amended), but not later than age 72 and, if I am a specified employee (within the meaning of such Section 409A of the Internal Revenue Code of 1986, as amended) when I separate from service, not earlier than six months following such separation from service to the extent required by such Section 409A .

___		As of the first business day of the calendar year after I attain age (not more than age 72).

Subject to the age 72 limitation, payment will not commence until at least five years after initial participation in the Plan.

I hereby direct that in the event of my death prior to the distribution in full of my interest in the Plan that any unpaid balance be paid to:


Name				Relationship



Address



Social Security No.				Date of Birth

(If you name more than one primary beneficiary, each primary beneficiary will share your benefit equally.)


Name				Relationship



Address



Social Security No.				Date of Birth

¨ REVISED CONTRIBUTION ELECTION

I hereby elect to change my contributions to the Executives’ Deferred Compensation Plan (the “Plan”) of Hawaiian Electric Industries, Inc. (the “Company”) and agree to be bound by the terms and conditions of the Plan.

This election form relates to services rendered for plan years beginning January 1, .

I hereby elect to defer receipt of:

% of my annual incentive compensation.

% of my long-term incentive compensation.

% of my annual and long-term incentive compensation.

¨ REVISED DISTRIBUTION ELECTION (Indicate Years of Deferral to Which this Revised Distribution Election Applies: )

(If this is a revised distribution election, to the extent required by Section 409A of the Internal Revenue Code of 1986, as amended, the election must be made at least twelve months before distribution would have otherwise commenced, and a minimum additional five year deferral period is required from the date of payment under the initial distribution election.)

I hereby direct that such deferred amounts be paid in:

A lump sum.

Annual installments over a period of years (not more than 10 years).

I hereby direct that the distribution of such deferred amounts commence the first business day of the calendar year: .

¨ REVISED DESIGNATION OF PRIMARY BENEFICIARY

I hereby direct that in the event of my death prior to the distribution in full of my interest in the Plan that any unpaid balance be paid to:


Name				Relationship



Address



Social Security No.				Date of Birth

(If you name more than one primary beneficiary, each primary beneficiary will share your benefit equally.)


Name				Relationship



Address



Social Security No.				Date of Birth

This beneficiary designation revokes any and all other beneficiary designations under the Plan made prior to the date of this designation.

By signing below, I acknowledge that I have read and understood the foregoing.


Signed by		Date
	Executive

Receipt acknowledged

Hawaiian Electric Industries, Inc.


By				Date

HAWAIIAN ELECTRIC INDUSTRIES, INC.

EXECUTIVES’ DEFERRED COMPENSATION PLAN

FORM 2—TERMINATION OF ELECTION FORM

I am an executive at:

¨ Hawaiian Electric Industries, Inc.

¨ Hawaiian Electric Company, Inc.

¨ Maui Electric Company, Limited

¨ Hawaii Electric Light Company, Inc.


Participant Name



Address



Social Security No.				Date of Birth

TO:

HAWAIIAN ELECTRIC INDUSTRIES, INC.

¨ TERMINATION OF ELECTION


(Indicate Date of Initial and Revised Elections )
		Dates

Effective January 1, , I hereby elect to terminate my participation in the Executives’ Deferred Compensation Plan. I understand that all amounts credited to my account under the Plan prior to such effective date of termination will remain subject to the terms and conditions of the Plan and will be paid to me or my beneficiary in accordance with my prior election(s).

By signing below, I acknowledge that I have read and understood the foregoing.


Signed by		Date
	Executive

Receipt acknowledged

Hawaiian Electric Industries, Inc.


By				Date

HEI Exhibit 10.3

HAWAIIAN ELECTRIC INDUSTRIES, INC.

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

TABLE OF CONTENTS


			Page
PROLOGUE			1

ARTICLE I		DEFINITIONS	1

ARTICLE II		SERVICE RULES
2.1	Credited Service Rules		3
2.2	Special Rule for Maternity or Paternity Absences		3

ARTICLE III		ELIGIBILITY	3

ARTICLE IV		CONTRIBUTIONS	4

ARTICLE V		BENEFITS
5.1	Normal Retirement Income		4
5.2	Early Retirement Income		4
5.3	Postponed Retirement Income		5
5.4	Normal Form of Benefits and Optional Forms		5
5.5	Death Benefit for Certain Participants		7
5.6	Small-Sum Cashouts		7
5.7	Special Rule for Certain Participants		7

ARTICLE VI		ADMINISTRATION
6.1	The Committee		8
6.2	Expenses		9

ARTICLE VII		INDEMNIFICATION	9

ARTICLE VIII		CLAIMS PROCEDURE
8.1	Claims Procedure		9
8.2	Review Procedure		10

ARTICLE IX		AMENDMENT, TERMINATION, AND MERGER
9.1	Amendment		11
9.2	Termination		11
9.3	Merger, Etc. of Company		11

ARTICLE X		MISCELLANEOUS
10.1	Right to Employment or Benefits		11
10.2	Inalienability		12
10.3	Facility of Payment		12
10.4	Construction of Plan		12
10.5	Forms		12
10.6	Forfeiture in the Event of Termination for Cause		12

HAWAIIAN ELECTRIC INDUSTRIES, INC.

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

PROLOGUE

Effective as of January 1, 1989, the “Hawaiian Electric Industries, Inc. Supplemental Executive Retirement Plan” (the “Plan”) was adopted by the Company as a spin off from the Hawaiian Electric Industries, Inc. Excess Benefit Plan (the “Excess Benefit Plan”), as amended and restated as of such date. The benefits accrued under the Excess Benefit Plan as of such date by participants of this Plan were spun off to this Plan on January 1, 1989. The Plan as set forth herein is amended and restated as of January 1, 2009.

This Plan is not intended to meet or be subject to the qualification requirements of Section 401 of the Internal Revenue Code of 1986, as amended. This Plan is intended to be an unfunded plan maintained by an employer primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees and thus exempt from Parts 2, 3 and 4 of Title I of the Employee Retirement Income Security Act of 1974, as amended.

ARTICLE I

DEFINITIONS

The following terms as used herein shall have the indicated meaning unless a different meaning is plainly required by the context. Whenever appropriate, words used in the singular may include the plural and vice versa and the masculine gender shall always include the feminine gender.

1.1 Accrued Benefit means the Participant’s accrued benefit determined hereunder and expressed in the form of an annual benefit commencing at the Participant’s Normal Retirement Date.

1.2 Actuarial Equivalent means an amount and form of benefit certified by an actuary to be mathematically equivalent in value to a given amount and form of benefit on the basis of the assumptions applicable under the Retirement Plan. Plan benefits that are deemed to be “actuarially reduced,” “actuarially increased,” or “actuarially adjusted” shall be computed as the Actuarial Equivalent of the benefit being replaced.

1.3 Associated Company means the Company and any corporation that is a member of the same controlled group of corporations (within the meaning of Section 1563(a) of the Code, determined without regard to Section 1563(a)(4) and (e)(3)(C) of the Code) as the Company. A corporation shall be regarded as an Associated Company only during the period it is a member of such controlled group of corporations.

1.4 Code means the Internal Revenue Code of 1986, as amended.

1.5 Committee means the Compensation Committee of the Company’s Board of Directors.

1.6 Company means Hawaiian Electric Industries, Inc.

1.7 Compensation means the Participant’s wages, salaries, and bonuses (including for the year for which it is earned any bonus under the Hawaiian Electric Industries, Inc. Executive Incentive Compensation Plan, but excluding any bonus that is paid or deferred pursuant to the Hawaiian Electric Industries, Inc. Long-Term Incentive Plan) received for personal services actually rendered in the course of employment with an Associated Company prior to reduction for an arrangement qualifying under Section 125 or 401(k) of the Code.

1.8 Credited Service means the period of employment for which benefit accrual credit is given under Article II.

1.9 Early Retirement Date , with respect to any Participant, means the attainment of age fifty-five (55) or, in respect of those Participants who first participated in the Plan after 2008, the attainment of at least age fifty-five (55) with at least five (5) years of participation in the Plan.

1.10 ERISA means the Employee Retirement Income Security Act of 1974, as amended.

1.11 Final Average Compensation means the average annual Compensation of a Participant during the three 12-month calendar periods during the Participant’s last 60 months of Credited Service affording the highest such average.

1.12 Joint and Survivor Annuity means an annuity (i) for the life of the Participant with a survivor annuity for the life of the spouse of the Participant to whom he or she is married at the time of his or her death (or, if different, his or her designated beneficiary under the Retirement Plan) that is one-half of the amount of the retirement income payable during the joint lives of the Participant and the Participant’s spouse (or designated beneficiary), and (ii) that is the Actuarial Equivalent of a single life annuity for the life of the Participant.

1.13 Normal Retirement Date , with respect to any Participant, shall have the meaning given such term under the Retirement Plan as in effect as of the first date of the Participant’s participation hereunder.

1.14 Participant means an officer of the Company or an Associated Company whose participation in this Plan is approved by resolution of the Committee.

1.15 Plan means this Hawaiian Electric Industries, Inc. Supplemental Executive Retirement Plan.

1.16 Plan Year means the calendar year.

1.17 Postponed Retirement Date , with respect to any Participant, shall have the meaning given such term under the Retirement Plan as in effect as of the first date of the Participant’s participation hereunder.

1.18 Primary Social Security Benefit means the monthly amount of primary old age insurance benefits available to a Participant at the earliest age at which Social Security benefits are available, or at date of retirement, if later (the “Social Security Commencement Age”), under the provisions of Title II of the Social Security Act as in effect for the year during which the Participant has a Separation from Service, assuming no future earnings from the year of separation, a 4.50% annual increase in the national average wage and a 3.75% annual cost of living increase in years subsequent to the year of Separation through the Social Security Commencement Age.

1.19 Retirement Plan means the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries, as amended from time to time.

1.20 Separation from Service means a separation from service within the meaning of Section 409A of the Code.

ARTICLE II

SERVICE RULES

Section 2.1 Credited Service Rules

(a) Credited Service shall be granted for the period of time beginning with the initial date on which the Participant commenced employment with an Associated Company to the date the Participant has a Separation from Service with all of the Associated Companies.

(b) If a Participant who was formerly employed by any of the Associated Companies is re-employed by an Associated Company and re-admitted as a Participant of this Plan by the Committee, in addition to the Credited Service granted in (a), Credited Service shall be granted for the period of time beginning with the date the Participant commences participation after such re-employment to the date the Participant subsequently has a Separation from Service with all of the Associated Companies.

Section 2.2 Special Rule for Maternity or Paternity Absences

If a Participant is absent from work for any period (i) by reason of pregnancy, the birth of a child, or the placement of a child with a Participant in connection with the adoption of such child or (ii) for purposes of caring for such child for a period beginning immediately following such birth or placement, the Participant shall be granted Credited Service for such period to the extent credited under the Retirement Plan.

ARTICLE III

ELIGIBILITY

An officer of an Associated Company shall be a Participant only if and as of when his participation in the Plan has been approved by the Committee (provided that, if no effective date of participation is specified, participation shall commence as of the date of such approval and provided further that participation shall not commence before the Participant first performs an hour of service for the Company or an Associated Company). However, in no event may a

Participant who is entitled to a benefit under this Plan also be eligible to participate in the Hawaiian Electric Industries, Inc. Excess Pay Plan. Subject to Section 9.2 of this Plan, a Participant shall not be entitled to a benefit under this Plan except to the extent the Participant is vested in the Retirement Plan or, in respect of those Participants who first participated in the Plan after 2008, unless and until the Participant has completed five years of continuous participation in the Plan.

ARTICLE IV

CONTRIBUTIONS

The Associated Companies shall pay the entire cost of the Plan from their general assets. No separate trust fund shall be established in connection with the Plan.

ARTICLE V

BENEFITS

Section 5.1 Normal Retirement Income

The monthly amount of retirement income commencing as of the Participant’s Normal Retirement Date on a single life basis shall be as follows:

(a) (i) The product of the Participant’s years of Credited Service and 2.04% (but not more than a total of 60%), multiplied by the Participant’s Final Average Compensation, reduced by (ii) (1) the Participant’s Primary Social Security Benefit, (2) the benefit payable under the Retirement Plan as of his Normal Retirement Date (calculated without regard to the cost of living increases provided for in Section 4.10 of the Retirement Plan), (3) the benefit payable as of his Normal Retirement Date under the American Savings Bank Retirement Plan, and (4) the amount payable to the Participant upon the commencement of participation under this Plan from the American Savings Bank Supplemental Executive Retirement, Disability and Death Benefit Plan.

(b) Notwithstanding any provision herein to the contrary (including the age requirements of this Plan), a Participant shall receive as retirement income (as determined on an annual basis) at least the amount which would have been paid, as of December 31, 2008, pursuant to the benefit formula stated in Section 4.2 of the Hawaiian Electric Industries, Inc. Excess Pay Supplemental Executive Retirement Plan.

Section 5.2 Early Retirement Income

(a) If a Participant has a Separation from Service on an Early Retirement Date, his monthly retirement income commencing as of his Early Retirement Date shall be the retirement income payable pursuant to Section 5.1(a)(i) of this Plan, reduced to reflect the fact that payments shall commence as of an earlier date according to the following scale interpolated to the nearest full month (provided, however, that no such reduction may exceed the Actuarial Equivalent reduction permitted to reflect the fact that payments shall commence earlier) and then further reduced by the amounts described in Section 5.1(a)(ii) of this Plan (but determined in the case of Sections 5.1(a)(ii)(2), (3) & (4), as of his Early Retirement Date).


Age at Retirement*		Remainder Percentage Applicable at Retirement
65 – 60		100%
59		99%
58		98%
57		97%
56		96%
55		95%
54		90%
53		85%
52		80%
51		75%
50		70%

*	For purposes of determining a Participant’s age at his Early Retirement Date under this scale, a Participant’s actual age shall be increased by one full year for each full year of Credited Service in excess of 33 years of Credited Service.

(b) A Participant who has satisfied the Credited Service requirements for an Early Retirement Date, but incurred a Separation from Service with the Company and the Associated Companies before satisfying the age requirement for an early retirement income, shall be entitled as of satisfaction of such age requirement to a benefit payable pursuant to Section 5.1(a)(i) of the Plan, reduced to an Actuarial Equivalent in accordance with Section 4.2(b) of the Retirement Plan and then further reduced by the amounts described in Section 5.1(a)(ii) of this Plan (but determined in the case of Sections 5.1(a)(ii)(2), (3) & (4), as of his or her Early Retirement Date).

Section 5.3 Postponed Retirement Income

If a Participant remains employed subsequent to his Normal Retirement Date and has a Separation from Service on a Postponed Retirement Date, his retirement income commencing as of his Postponed Retirement Date shall be computed based upon his Credited Service and Compensation (including Credited Service and Compensation credited subsequent to his Normal Retirement Date) as of his Postponed Retirement Date.

Section 5.4 Normal Form of Benefits and Optional Forms

(a) Subject to Section 5.2(b) and the following provisions of this Section 5.4, the benefits payable under this Plan shall commence as soon as practicable (but in any event within ninety (90) days) following the Participant’s Separation from Service (but in the case of a Participant who has a Separation from Service before his or her Early Retirement Date, not before what would have been the Participant’s Early Retirement Date had there been no Separation from Service) in the form of a single life annuity. Notwithstanding the foregoing, a

Participant may elect, in accordance with the following provisions of this Article V, to have payment made in the form of any other life annuity available at the time of payment under the Retirement Plan (other than an option for a lump sum or the adjustment for Federal Old Age Benefits (Social Security)), based on the same actuarial assumptions used in determining optional forms of benefits under the Retirement Plan as in effect as of the time of payment.

(b) A Participant may elect in the form and manner provided by the Committee within thirty (30) days of first becoming a Participant that benefits payable under this Plan (i) shall not commence upon his Separation from Service but rather shall be paid commencing on (or as soon as practicable but in any event within ninety (90) days following) January 1 of either (A) a calendar year specified by the Participant, provided such calendar year commences after the Participant’s Separation from Service (but in the case of a Participant who has a Separation from Service before his or her Early Retirement Date, not before what would have been the Participant’s Early Retirement Date had there been no Separation from Service), or (B) a calendar year that begins a number of years (as specified by the Participant) after the Participant’s Separation from Service (but in the case of a Participant who has a Separation from Service before his or her Early Retirement Date, not before what would have been the Participant’s Early Retirement Date had there been no Separation from Service), and (ii) shall be payable in any form of benefit available at the time of the election under the Retirement Plan (provided that, if the Participant specifies a life annuity, the Participant shall not be required to specify the particular type of life annuity until payments commence), other than an option for a lump sum or the adjustment for Federal Old Age Benefits (Social Security), based on the same actuarial assumptions used in determining optional forms of benefits under the Retirement Plan as in effect as of the time of payment.

(c) A Participant who has made an election as described in subsection (b), above, or who is deemed (by failing to make an election in accordance with subsection (b), above) to have elected payment in the form of a single life annuity commencing upon Separation from Service, may change such election in the form and manner provided by the Committee provided that, to the extent required by Section 409A of the Code, (i) such election may not take effect until at least twelve (12) months after the date on which the election is made, (ii) the commencement of payment is deferred for a period of not less than five (5) years from the date the first amount was scheduled to be paid, and (iii) the election is made not less than twelve (12) months before the date the first amount was scheduled to be paid.

(d) Notwithstanding the foregoing provisions of this Section 5.4, no payment shall be made until at least six (6) months following a Participant’s Separation from Service and all amounts that otherwise would have been payable during such six-month period shall be paid (without interest) to the Participant in a lump sum as soon as practicable (but in any event within five (5) business days) following the expiration of such six-month period, and subsequent payments under the Plan shall be made in accordance with the terms of the Plan determined without regard to such six-month delay requirement.

Section 5.5 Death Benefit for Certain Participants

(a) If a Participant dies while entitled to benefits under the Plan but before the payment of benefits has commenced under the Plan, his surviving spouse (or, if different, his designated beneficiary under the Retirement Plan) shall receive a benefit equal to the “survivor annuity” described in Section 5.5(b) of this Plan that commences as soon as practicable (but in any event within ninety (90) days) following the Participant’s death or, if later, the Participant’s Early Retirement Date (determined as if the Participant had not had a Separation from Service).

(b) For purposes of this Section 5.5, “survivor annuity” means a survivor annuity for the life of the surviving spouse or, if none, the designated beneficiary of the Participant under which the payments to the surviving spouse or designated beneficiary are equal to the amounts that would be payable as a survivor annuity under a Joint and Survivor Annuity based on the benefit calculated under Section 5.1, 5.2 or 5.3 of this Plan, provided that the Retirement Plan shall pay so much of that benefit as is permitted under the terms of the Retirement Plan, with the excess being paid from this Plan. In the case of a Participant who has not attained his or her Early Retirement Date at the time of death, the survivor annuity shall be calculated as if such Participant had (i) separated from service on his or her date of death, (ii) survived to his or her Early Retirement Date, (iii) retired with an immediate Joint and Survivor Annuity at his or her Early Retirement Date, and (iv) died on the day after the day on which he or she would have attained his Early Retirement Date.

Section 5.6 Small-Sum Cashouts

Notwithstanding the foregoing provisions of this Article V but subject to the provisions of Section 5.4(d), if the Actuarial Equivalent lump-sum present value of the benefit otherwise payable in accordance with the preceding provisions of this Article V is not more than $100,000, determined as of the date as of which payment of benefits otherwise would have commenced, the benefit shall be paid to the Participant (or his or her beneficiary, as the case may be) in one lump-sum payment.

Section 5.7 Special Rule for Certain Participants

(a) The provisions of this Section 5.7 shall apply only to Participants who accrued no benefit under the Plan after 2004 and, in respect of the Accrued Benefit of any Participant who retired as Chief Executive Officer of the Company before 2009, the portion of such Accrued Benefit that was earned and vested (within the meaning of Section 409A of the Code) before 2005.

(b) Notwithstanding any other provision of this Plan, if a “change of control” (as defined in Section 5.7(c) occurs, then the Actuarial Equivalent of the Accrued Benefit (or applicable portion thereof) of each such Participant who is retired (or if the retired Participant has died, the portion of his or her Accrued Benefit (or applicable portion thereof) to which his or her spouse or other beneficiary is entitled) shall be paid in a lump sum to the retired Participant (or if the retired Participant has died, his or her spouse or other beneficiary) within 30 days of the date of such change in control.

(c) For the purposes of this Section 5.7, a “change of control” shall be deemed to have taken place if (i) any person, including a group as defined in Section 13(d)(3) of the Securities Exchange Act of 1934, becomes the beneficial owner of shares of the Company having 25% or more of the total number of votes that may be cast for the election of Directors of the Company; (ii) as the result of, or in connection with, any cash tender or exchange offer, merger, or other business combination, sale of assets, or contested election, or any combination of the foregoing transactions, the persons who were Directors of the Company before the transaction shall cease to constitute a majority of the Board of Directors of the Company or any successor to the Company; or (iii) a majority of the Board of Directors of the Company determines in good faith that a “change of control” is imminent.

ARTICLE VI

ADMINISTRATION

Section 6.1 The Committee

(a) The Committee shall be responsible for the administration of the Plan. The Committee shall have the sole authority, in its discretion, to adopt, amend, and rescind such rules and regulations as it deems advisable for the administration of the Plan, to construe and interpret the Plan and its provisions, to resolve any ambiguities in the Plan’s provisions, and to make all determinations under the Plan, including determining the rights of Participants and beneficiaries and the amount of any benefits payable under the Plan. All decisions, determinations, and interpretations of the Committee shall be final and binding upon all persons.

(b) The Committee shall have the power to delegate specific responsibilities to any person or group of persons, and such person or group may serve in more than one such delegated capacity. Such delegations may be to employees of an Associated Company or to other individuals, all of whom shall serve at the pleasure of the Committee and the Company, and if full-time employees of an Associated Company, without compensation. Any such person may resign by delivering a written resignation to the Committee.

(c) Without limiting the foregoing provisions of this Article VI, the Committee shall have the following specific duties and responsibilities in addition to any other duties specified in the Plan or by applicable law.

(1) Subject to the limitations contained in this Plan, the Committee shall adopt rules for the administration of the Plan as it considers desirable, provided such rules do not conflict with the Plan.

(2) The Committee may authorize an agent, to act on its behalf, and may contract for legal, actuarial, medical, accounting, clerical, and other services to carry out the Plan and to discharge its responsibilities.

(3) Except as otherwise expressly provided herein, the Committee in its discretion may interpret and construe the Plan, or reconcile inconsistencies to the extent necessary to effectuate the Plan, and such action shall be binding upon all persons.

(4) The Committee shall adopt from time to time actuarial tables and actuarial methods for use in all actuarial calculations, if any, required in connection with the determination of benefit payments under the Plan.

(5) The Committee shall be responsible for the maintenance of all employee, Participant, and beneficiary records for the Plan. The Committee shall also be responsible for the maintenance of records, appropriate notifications, and filings in connection with the interest of all Participants or their spouses or contingent annuitants.

Section 6.2 Expenses

The Associated Companies shall pay all expenses of administering the Plan. Such expenses shall include any expenses incurred by an Associated Company or the Committee, including, but not limited to, the payment of professional fees of consultants.

ARTICLE VII

INDEMNIFICATION

The Associated Companies shall indemnify and save harmless and/or insure the members of the Committee and each person who is an employee or a director of an Associated Company, and may indemnify and/or insure those to whom the Committee has delegated its duties, against any and all claims, losses, damages, expenses, and liability arising from their responsibilities in connection with this Plan, if the person acted in good faith and in a manner the person reasonably believed to be in or not opposed to the best interests of the Associated Companies.

ARTICLE VIII

CLAIMS PROCEDURE

Section 8.1 Claims Procedure

A Participant or beneficiary or any other person who has not received benefits under this Plan that he or she believes should be paid (each, a “Claimant”) may make a claim for benefits as follows:

(a) Written Claim . The Claimant may initiate a claim by submitting to the Company a written claim for benefits.

(b) Timing of Company Response . The Company shall respond to the Claimant within 90 days after receiving the claim. If the Company determines that special circumstances require additional time for processing the claim, the Company may extend the response period by an additional 90 days by notifying the Claimant in writing, prior to the end of the initial 90-day period, that an additional period is required. The notice of extension shall set forth the special circumstances and the date by which the Company expects to render its decision.

denial is based; (iii) a description of any additional information or material necessary for the Claimant to perfect the claim and an explanation of why it is needed; (iv) an explanation of the review procedures in Section 8.2 and the time limits applicable to such procedures; and (v) a statement of the Claimant’s right to bring a civil action under ERISA Section 502(a) following an adverse benefit determination on review.

Section 8.2 Review Procedure

If the Company denies part or all of the claim, the Claimant shall have the opportunity for a full and fair review of the denial by the Committee as follows:

(a) Written Request . In order to initiate the review, the Claimant, within 180 days after receiving the Company’s notice of denial, may file with the Committee a written request for review. The Claimant shall then have the opportunity to submit written comments, documents, records, and other information relating to the claim. The Company shall provide the Claimant, upon request and free of charge, reasonable access to, and copies of, all documents, records, and other information relevant (as defined in applicable ERISA regulations) to the Claimant’s claim for benefits.

(b) Considerations on Review . In considering the claim on review, the Committee shall take into account all materials and information the Claimant submits relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination. No deference shall be given to the initial adverse benefit determination.

(c) Timing of Committee Response . The Committee shall respond in writing to such Claimant within 60 days after receiving the request for review. If the Committee determines that special circumstances require additional time for processing the claim, the Committee may extend the response period by an additional 60 days by notifying the Claimant in writing, prior to the end of the initial 60-day period, that an additional period is required. The notice of extension must set forth the special circumstances and the date by which the Committee expects to render its decision.

(d) Notice of Decision . If the Committee denies part or all of the claim, the Committee shall notify the Claimant in writing of its decision on review. The Committee shall write the notification in a manner calculated to be understood by the Claimant. The notification shall set forth: (i) the specific reasons for the denial; (ii) a reference to the specific provisions of the Plan on which the denial is based; (iii) a statement that the Claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records, and other information relevant (as defined in applicable ERISA regulations) to the Claimant’s claim for benefits; and (iv) a statement of the Claimant’s right to bring a civil action under ERISA Section 502(a) after exhausting all administrative claims and review procedures in this Article VIII.

ARTICLE IX

AMENDMENT, TERMINATION, AND MERGER

Section 9.1 Amendment

Subject to the provisions hereinafter set forth, the Company reserves the right to amend the Plan at any time by action of its Board of Directors, and (to the extent permitted by applicable law) give any such amendment retroactive effect.

Section 9.2 Termination

The continuation of the Plan is not assumed as a contractual obligation by any Associated Company. Each Associated Company reserves the right to terminate the Plan with respect to its participation at any time. If the Plan is terminated (in full or in part), (i) the then Accrued Benefit under this Plan of each affected Participant shall become 100% vested, except to the extent the Participant has not been a Participant for at least thirteen (13) months (in which case the Participant shall become 100% vested if and when he or she completes such 13-month service requirement), and (ii) the benefits payable under the Plan shall be payable in accordance with the terms of the Plan as in effect immediately before the termination.

Section 9.3 Merger, Etc, of Company

The Company shall not sell substantially all of its assets, merge, or consolidate with any other corporation or organization, or permit its business activities to be taken over by another organization, unless and until the succeeding or continuing corporation or other organization expressly assumes the obligations of the Company and the Associated Companies under this Plan.

ARTICLE X

MISCELLANEOUS

Section 10.1 Right to Employment or Benefits

(a) Nothing contained in the Plan shall be deemed to give any Participant a right to remain in the employment of any of the Associated Companies.

(b) (1) Nothing contained in the Plan shall be deemed to give any Participant or beneficiary any right or claim to benefits except as expressly provided in the Plan.

(2) Notwithstanding any other provision in this Plan, in the event the Company fails to fulfill its obligation to make payments to the Participant, his beneficiary, or any other person entitled to payments under the Plan, the Company shall be liable to such person for any attorney’s fees and other legal costs related to enforcing such person’s claim against the Company (to the extent the person prevails under such claim), provided that such fees and costs must be claimed by such person, and shall be paid by the Company, not later than the end of the person’s taxable year following the year in which the fees or costs were incurred.

Section 10.2 Inalienability

No Participant or any person having or claiming to have any interest of any kind or character in or under the Plan shall have any right to sell, assign, transfer, convey, hypothecate, anticipate, or otherwise dispose of such interest, and such interest shall not be subject to any liabilities or obligations of, or any bankruptcy proceedings, claims of creditors, attachment, garnishment, execution, levy, or other legal process against, such person or person’s property.

Section 10.3 Facility of Payment

If any Participant or beneficiary eligible to receive benefits under this Plan is, in the opinion of the Company, legally, physically, or mentally incapable of personally receiving and receipting for any payment under the Plan, the Company may direct payments to such other person, persons, or institutions who, in the opinion of the Company, are then maintaining or having custody of such payee, until claims are made by a duly appointed guardian or other legal representative of such payee. Such payments shall constitute a full discharge of the liability of the Plan to the extent thereof.

Section 10.4 Construction of Plan

(a) The headings of articles and sections are included herein solely for convenience of reference, and if there is any conflict between such headings and the text of the Plan, the text shall be controlling.

(b) To the extent not preempted by ERISA, the Plan shall be governed, construed, administered, and regulated according to the laws of the State of Hawaii.

Section 10.5 Forms

All consents, elections, applications, designations, etc. required or permitted under the Plan must be made on forms prescribed and furnished by the Committee, and shall be recognized only if properly completed, executed, and returned to the Committee.

Section 10.6 Forfeiture in the Event of Termination for Cause

Notwithstanding any other provision of this Plan to the contrary, a Participant shall not be entitled to any benefit under this Plan if the Company or an Associated Company terminates the Participant’s employment for “cause”. For purposes of this Section 10.6, “cause” means the Participant is terminated for violation of the Code of Conduct of an Associated Company.

TO RECORD the adoption of this amended and restated Plan, Hawaiian Electric Industries, Inc. has caused this document to be executed this 27 ^th day of October, 2008, effective as of January 1, 2009.


HAWAIIAN ELECTRIC INDUSTRIES, INC.

By		/s/ Patricia U. Wong
		Its Vice President-Administration & Corporate Secretary

HEI Exhibit 10.4

HAWAIIAN ELECTRIC INDUSTRIES, INC.

EXCESS PAY PLAN

PROLOGUE

This Plan amends and collectively restates, as of January 1, 2009, the Hawaiian Electric Industries, Inc. Excess Pay Supplemental Executive Retirement Plan and the Hawaiian Electric Industries, Inc. Excess Benefit Plan. This Plan is not intended to meet or be subject to the qualification requirements of Section 401 of the Internal Revenue Code of 1986, as amended. To the extent this Plan replaces benefits otherwise limited by Section 415 of the Code, it is intended to be an excess benefit plan within the meaning of Section 3(36) of ERISA and exempt from the provisions of Title I of ERISA. To the extent this Plan otherwise provides benefits, it is intended to be an unfunded plan maintained by an employer primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees and thus exempt from Parts 2, 3 and 4 of Title I of ERISA.

ARTICLE I

DEFINITIONS

The following terms as used herein shall have the indicated meaning, unless a different meaning is clearly required by the context. Whenever appropriate, words used in the singular may include the plural and vice versa, and the masculine gender shall always include the feminine gender.

1.1 Associated Company means the Company and any corporation that is a member of the same controlled group of corporations (within the meaning of Section 1563(a) of the Code, determined without regard to Section 1563(a)(4) and (e)(3)(C) of the Code) as the Company. A corporation shall be regarded as an Associated Company only during the period it is a member of such controlled group of corporations.

1.2 Code means the Internal Revenue Code of 1986, as amended.

1.3 Committee means the Compensation Committee of the Board of Directors of the Company.

1.4 Company means Hawaiian Electric Industries, Inc.

1.5 ERISA means the Employee Retirement Income Security Act of 1974, as amended.

1.6 Participant means any person meeting the eligibility requirements of Article II hereof.

1.7 Participating Employer means the Company and/or any other corporation that is a member of the same controlled group of corporations (as

defined in Section 414(b) of the Code) as the Company and to which participation in the Retirement Plan is extended.

1.8 Plan means this Hawaiian Electric Industries, Inc. Excess Pay Plan, as amended from time to time.

1.9 Retirement Plan means as to any Participant, whichever one of the following plans in which that individual is a participant: the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries as amended from time to time and the American Savings Bank Retirement Plan as amended from time to time.

1.10 Separation from Service means a separation from service within the meaning of Section 409A of the Code.

1.11 SERP means the Hawaiian Electric, Industries, Inc. Supplemental Executive Retirement Plan and American Savings Bank Supplemental Executive Retirement, Disability and Death Benefit, each as amended from time to time.

ARTICLE II

ELIGIBILITY

(a) Each participant in the Retirement Plan shall be a Participant in this Plan, excluding any participant: (i) whose benefits are subject to collective bargaining; (ii) not employed by a Participating Employer; or (iii) who is also entitled to a benefit under the SERP. Subject to Section 8.2 of this Plan, a Participant shall not be entitled to a benefit under this Plan unless and until (and to the extent) he or she is entitled to a benefit under the applicable Retirement Plan.

(b) The individuals referenced in Appendix I hereto shall also be considered Participants.

ARTICLE III

CONTRIBUTIONS

No contributions to this Plan from Participants shall be permitted or required.

ARTICLE IV

BENEFITS

Section 4.1 Excess Benefit

(a) This Plan shall provide to each Participant (exclusive of the individuals referenced in Appendix I hereto) a benefit equal to the amount that would be payable under the Retirement Plan (as of the date of payment hereunder) if the limits under Sections 401(a)(17) and 415 of the Code were not applicable over the amounts actually payable under the Retirement Plan (as of the date of payment hereunder).

(b) (1) Subject to Section 4.3 and the following provisions of this subsection (b), the benefits payable under this Plan shall commence as soon as practicable (but in any event within ninety (90) days) following the Participant’s Separation from Service in the form of a single life annuity or any other life annuity available at the time of payment under the applicable Retirement Plan and elected by the Participant; provided that, in the case of a Participant who participates in the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries, as amended from time to time, payment will not commence until the Participant has attained age fifty-five (55), and in the case of a Participant who participates in the American Savings Bank Retirement Plan, as amended from time to time, payment will not commence until the earlier of the Participant’s attainment of age sixty-five (65) or the Participant’s attainment of at least age 55 with vesting service under such plan of at least ten (10) years.

(2) Notwithstanding the foregoing provisions of this subsection (b), no payment shall be made to a Participant until at least six (6) months following the Participant’s Separation from Service and all amounts that otherwise would have been payable during such six-month period shall be paid to the Participant (without interest) in a lump sum as soon as practicable (but in any event within five (5) business days) following the expiration of such six-month period, and subsequent payments under the Plan shall be made in accordance with the terms of the Plan determined without regard to such six-month delay requirement.

Section 4.2 Payments following Death

If a Participant dies while entitled to benefits under the Plan but before benefits have commenced pursuant to Section 4.1, his or her surviving spouse (or in the case of a participant in the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries, as amended from time to time, his or her designated beneficiary under such plan if not his or her surviving spouse) shall receive a benefit equal to the “survivor annuity” described in the following provisions of this Section 4.2 that commences as soon as practicable (but in any event within ninety (90) days) following the Participant’s death or, if later, the date

the Participant would have attained age fifty-five (55). No benefit shall be payable under this Plan in respect of a Participant who dies before benefits have commenced pursuant to Section 4.1, who has no surviving spouse and who, at the time of his or her death, was a Participant in the American Savings Bank Retirement Plan.

For purposes of this Section 4.2, “survivor annuity” means a survivor annuity for the life of the surviving spouse (or designated beneficiary, as the case may be) under which the payments to the surviving spouse or designated beneficiary are equal to the amounts that would be payable as an actuarially equivalent (based on the actuarial assumptions applicable under the Retirement Plan at the date of death) survivor annuity under a joint and 50% survivor annuity based on the benefit calculated under Section 4.1, provided that the Retirement Plan shall pay so much of that benefit as is permitted under the terms of the Retirement Plan, with the excess being paid from this Plan. If the Participant dies before the date on which he or she would have attained age fifty-five (55), the survivor annuity shall be calculated as if such Participant had (i) separated from service on his or her date of death, (ii) survived to such date, (iii) retired with an immediate such joint and survivor annuity at such date, and (iv) died on the day after such date.

Section 4.3 Small-Sum Cashouts

Subject to the provisions of Section 4.1(b)(2): (a) to the extent the lump-sum present value (as determined under the provisions of the applicable Retirement Plan) of the benefit otherwise payable in accordance with Section 4.1 or 4.2, when aggregated with the benefit payable under any other arrangement with which the Plan must be aggregated pursuant to Section 409A of the Code, does not exceed the annual limit on deferrals under Section 402(g) of the Code, determined as of the date of separation from service or death, as the case may be, the benefit shall be paid to the Participant (or his or her beneficiary, as the case may be) in one lump-sum payment, and (b) to the extent the lump-sum present value (as determined under the provisions of the applicable Retirement Plan) of the benefit otherwise payable in accordance with Section 4.1 or 4.2 is not more than $100,000, determined as of the date as of which payment of benefits otherwise would have commenced, the benefit shall be paid to the Participant (or his or her beneficiary, as the case may be) in one lump-sum payment.

Section 4.4 Forfeiture in the Event of Termination for Cause

Notwithstanding any other provision of this Plan to the contrary, a Participant shall not be entitled to any benefit under this Plan if a Participating Employer or an Associated Company terminates the Participant’s employment for “cause”. For purposes of this Section 4.4, “cause” means the Participant is terminated for violation of the Code of Conduct of the Company or American Savings Bank, F.S.B.

Section 4.5 Application of Article IV

This Article IV applies only to Participants other than those referenced in Appendix I.

ARTICLE V

ADMINISTRATION

Section 5.1 The Committee

(c) Without limiting the foregoing provisions of this Article V, the Committee shall have the following specific duties and responsibilities in addition to any other duties specified in the Plan or by applicable law.

(1) Subject to the limitations contained in this Plan, the Committee shall adopt rules for the administration of the Plan as it considers desirable, provided such rules do not conflict with the Plan.

Section 5.2 Expenses

The Participating Employers shall pay all expenses of administering the Plan. Such expenses shall include any expenses incurred by a Participating Employer or the Committee, including, but not limited to, the payment of professional fees of consultants.

ARTICLE VI

NO TRUST FUND

No separate trust fund shall be established in connection with this Plan. This Plan shall be unfunded and the benefits thereof paid as necessary from the general assets of the Participating Employers.

ARTICLE VII

CLAIMS PROCEDURE

Section 7.1 Claims Procedure

(a) Written Claim . The Claimant may initiate a claim by submitting to the Company a written claim for benefits.

(c) Notice of Decision . If the Company denies part or all of the claim, the Company shall notify the Claimant in writing of such denial. The Company shall write the notification in a manner calculated to be understood by the Claimant. The notification shall set forth: (i) the specific reasons for the denial; (ii) a reference to the specific provisions of the Plan on which the denial is based; (iii) a description of any additional information or material necessary for the Claimant to perfect the claim and an explanation of why it is needed; (iv) an explanation of the review procedures in Section 7.2 and the time limits applicable to such procedures; and (v) a statement of the Claimant’s right to bring a civil action under ERISA Section 502(a) following an adverse benefit determination on review.

Section 7.2 Review Procedure

If the Company denies part or all of the claim, the Claimant shall have the opportunity for a full and fair review of the denial by the Committee as follows:

based; (iii) a statement that the Claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records, and other information relevant (as defined in applicable ERISA regulations) to the Claimant’s claim for benefits; and (iv) a statement of the Claimant’s right to bring a civil action under ERISA Section 502(a) after exhausting all administrative claims and review procedures in this Article VII.

ARTICLE VIII

AMENDMENT AND TERMINATION

Section 8.1 Amendment

Section 8.2 Termination

The continuation of the Plan is not assumed as a contractual obligation by any Participating Employer. Each Participating Employer reserves the right to terminate the Plan with respect to its participation at any time. If the Plan is terminated (in full or in part), the then accrued benefit under this Plan of each affected Participant shall become 100% vested, and the benefits payable under the Plan shall be payable in accordance with the terms of the Plan as in effect immediately before the termination.

ARTICLE IX

INDEMNIFICATION

ARTICLE X

MISCELLANEOUS

Section 10.1 Right to Employment Or Retirement Income

(a) Nothing contained in the Plan shall be deemed to give any Participant a right to remain in the employ of the Participating Employers.

(b) (1) Nothing contained in the Plan shall be deemed to give any Participant, retired Participant, spouse, beneficiary or contingent annuitant any right or claim to any benefit except as expressly provided in the Plan.

Section 10.2 Inalienability

No Participant or any person having or claiming to have any interest of any kind or character in or under this Plan shall have any right to sell, assign, transfer, convey, hypothecate, anticipate, or otherwise dispose of such interest, and such interest shall not be subject to any liabilities or obligations of, or any bankruptcy proceedings, claims of creditors, attachment, garnishment, execution, levy, or other legal process against such person or such person’s property.

Section 10.3 Facility Of Payment

If any Participant, retired Participant, or spouse or contingent annuitant eligible to receive payments under this Plan is, in the opinion of the Committee, legally, physically, or mentally incapable of personally receiving and receipting for any payment under this Plan, the Committee may direct payments to such other person, persons, or institutions who, in the opinion of the Committee, are then maintaining or having custody of such payee, until claims are made by a duly appointed guardian or other legal representative of such payee. Such payments shall constitute a full discharge of the liability of the Plan to the extent thereof.

Section 10.4 Construction Of Plan

(a) The headings of articles and sections are included herein solely for the convenience of reference, and if there is any conflict between such headings and the text of this Plan, the text shall be controlling.

(b) To the extent not preempted by ERISA, the Plan shall be governed, construed, administered and regulated according to the laws of the State of Hawaii.

Section 10.5 Forms

All consents, elections, applications, designations, etc. required or permitted under the Plan (if any) must be made on forms prescribed and furnished by the Committee, and shall be recognized only if properly completed, executed, and returned to the Committee.

Section 10.6 Effective Date

TO RECORD the adoption of this Plan, the undersigned have caused this document to be executed this 27 ^th day of October 2008, effective as of January 1, 2009.


HAWAIIAN ELECTRIC INDUSTRIES, INC.

By		/s/ Patricia U. Wong
		Its Vice President-Administration & Corporate Secretary

APPENDIX I

Certain individuals shall be participants in the Plan and eligible for benefits under the Plan in a manner different from that provided under the otherwise applicable terms of the Plan. Such individuals and the benefits to which they are entitled are identified in a schedule maintained by the employee benefits department of the Hawaiian Electric Company, Inc.

HEI Exhibit 10.5

HAWAIIAN ELECTRIC INDUSTRIES, INC.

NON-EMPLOYEE DIRECTORS’ DEFERRED COMPENSATION PLAN

PREAMBLE

The following sets forth the terms of the Non-Employee Directors’ Deferred Compensation Plan of Hawaiian Electric Industries, Inc., as amended. This Plan is an unfunded deferred compensation arrangement solely for non-employee directors of the Company and the Participating Subsidiaries.

ARTICLE I

EFFECTIVE DATE AND CERTAIN DEFINITIONS

1.1 The original effective date of the Plan was September 9, 1980. The Plan was amended and restated in its entirety effective for elections made on or after January 1, 1990 and was again amended and restated effective for elections made with regard to directors’ fees earned on or after January 1, 1991. The Plan as amended and restated herein is effective as of the Effective Date.

“Committee” shall mean the Compensation Committee of the Board of Directors of the Company.

“Company” shall mean Hawaiian Electric Industries, Inc.

“Effective Date” shall mean January 1, 2009.

“Eligible Director” shall have the meaning ascribed thereto in Article II of the Plan.

“Participating Subsidiaries” shall mean, collectively, Hawaiian Electric Company, Inc., Hawaii Electric Light Company, Inc., Maui Electric Company, Limited and American Savings Bank, F.S.B.

“Plan” shall mean this Non-Employee Directors’ Deferred Compensation Plan of Hawaiian Electric Industries, Inc., as amended from time to time.

“Plan Administrator” shall mean the Vice President—Administration of the Company.

“Section 409A” shall mean Section 409A of the Internal Revenue Code of 1986, as amended.

ARTICLE II

ELIGIBILITY

Any non-employee director of the Company or the Participating Subsidiaries entitled to compensation from the Company or the Participating Subsidiaries for service as a director (an “Eligible Director”) shall be eligible to elect to participate in the Plan.

ARTICLE III

ELECTION TO PARTICIPATE IN THE PLAN

3.1 An Eligible Director may at any time elect in writing on a form furnished by and filed with the Plan Administrator to participate in the Plan and thereby defer receipt of all or a specified portion of his or her director’s retainer and/or meeting fees. The form for such election shall be substantially similar to the attached Form 1 or such other form as may be approved by the Plan Administrator. Once made, an election shall apply to all succeeding years unless revised or revoked pursuant to Section 3.3.

3.2 Such election shall be effective on the January 1 of the calendar year following the receipt of the election by the Plan Administrator, with respect to any Eligible Director’s retainer and/or meeting fees owing for service performed during that calendar year and any succeeding year, except that an Eligible Director who is elected to fill a vacancy on the Board of Directors mid-year and who was therefore not a director on the preceding December 31 may make an election, before his or her term begins, to defer receipt of all or a specified portion of his or her director’s retainer and/or meeting fees for the remainder of the calendar year in which such term begins, and for succeeding calendar years.

3.3 An Eligible Director may at any time and from time to time in writing on a form furnished by and filed with the Plan Administrator change the terms of his or her election or terminate his or her participation in the Plan, effective as of the January 1 of the calendar year following the receipt of such form by the Plan Administrator with respect to any director’s retainer and/or meeting fees owing for services performed on or after that effective date. Specimen forms for a revised election and for termination of participation are included in the attached Forms 1 and 2, which Forms may be modified by the Plan Administrator, as he or she deems appropriate. However, all amounts deferred pursuant to the Plan prior to the effective date of such revised election or termination shall continue to be subject to the terms of the prior election by the Eligible Director in effect when such amounts were credited under the Plan or any subsequent further deferral by the Eligible Director effected in accordance with Section 409A.

3.4 An Eligible Director who terminates his or her participation in the Plan shall not be eligible to participate again in the Plan until the January 1 following the January 1 on which his or her termination of participation takes effect.

(2)

ARTICLE IV

ACCOUNTS

4.1 The Company shall maintain book accounts on behalf of each Eligible Director who elects to participate in the Plan. The amounts of meeting fees to be deferred under this Plan, if any, shall be credited to the applicable Eligible Director’s account as of the end of each month; and the amounts of retainer fees to be deferred under the Plan, if any, shall be credited to the applicable Eligible Director’s account as of the end of the month in which paid. The Company does not intend to set aside any cash or other assets to fund these accounts. Payments shall be made from the general funds of the Company when due under the terms of this Plan. Nothing contained in the Plan and no action pursuant to the provisions of the Plan shall be construed to create a trust of any kind.

4.2 Amounts credited to an Eligible Director’s account shall be credited each year with an amount equivalent to interest, compounded quarterly, at the annual rate commensurate with the prevailing interest rate on three-year certificates of deposit at American Savings Bank, F.S.B., as of January 1 of that year; provided, however, that the balance of the Eligible Director’s account as of December 31, 1990 shall be credited annually with interest at the rate of 2.5 percent (2.5%) per quarter, compounded quarterly. Such accrued interest shall be payable to the Eligible Director at the same time as the deferred amounts are paid to the Eligible Director.

4.3 Whether or not the Company sets aside any funds or invests any funds in contemplation of its obligations hereunder, all amounts deferred pursuant to the Plan (including deferred compensation and interest thereon) shall remain part of the general funds of the Company and no Eligible Director shall acquire any property interest in his or her account, stock, or other assets of the Company or a Participating Company, his or her right being limited to receiving from the Company deferred payments measured as set forth in this Plan. This right is conditioned upon continued compliance with the terms and conditions of this Plan. To the extent that any Eligible Director acquires a right to receive benefits under this Plan, such right shall be no greater than the right of any unsecured general creditor of the Company.

4.4 Neither the account of, nor the right to receive payments under the Plan of, the Eligible Director or his or her beneficiary shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, or encumbrance and such account or right may not be subject to the debts, contracts, liabilities, engagements or torts of the Eligible Director or his or her beneficiary.

ARTICLE V

DISTRIBUTIONS

5.1 (a) Amounts deferred under the Plan shall be distributed in accordance with the written, irrevocable election of the Eligible Director on a form furnished and filed with the Plan Administrator as provided in Article III. The Eligible Director shall indicate when such payments are to commence and the form of distribution.

(3)

(b) Payments under the Plan will commence on the first business day of the calendar year selected by the Eligible Director, but payments must commence (1) not later than the first business day of the calendar year following the Eligible Director’s attainment of age 72 and (2) subject to (1) above, not earlier than the first business day of the calendar year which is at least five (5) full years after the date of the Eligible Director’s initial deferral election.

(c) (1) Payments, at the Eligible Director’s election, shall either be in lump sum or in substantially equal annual installments over a period of years not exceeding ten years.

(2) The amount of the installment payments shall be determined as follows. The total amount of deferred income (deferred compensation and interest thereon) in the Eligible Director’s account as of the elected payment commencement date will be paid in equal annual payments over the number of years elected. Each annual payment, other than the first payment, shall include an additional amount equal to interest, compounded quarterly, at the rate specified in Section 4.2, on the amount in the Eligible Director’s account as of the December 31 preceding such payment.

5.2 (a) Upon the death of an Eligible Director or former Eligible Director prior to the expiration of the period during which the deferred amounts are payable, the balance of the deferred amounts will be paid on the first business day of the calendar year following the year of death in one lump-sum to such person or persons designated by the Eligible Director or former Eligible Director in writing on a form furnished by and filed with the Plan Administrator. A specimen form for such beneficiary designation is attached as part of Form 1, which Form may be modified by the Plan Administrator, as he or she deems appropriate. In the absence of such designation, the payment will be made to the Eligible Director’s or former Eligible Director’s estate.

(b) The amount payable on the first business day of the calendar year following an Eligible Director’s or former Eligible Director’s death shall be the dollar amount (deferred compensation plus interest) credited to his or her account as of the December 31 following his or her date of death.

5.3 In the event of an unforeseeable emergency (within the meaning of Section 409A) proven to the satisfaction of the Committee, an Eligible Director or former Eligible Director with an account under the Plan may receive an accelerated distribution of up to 50% of the amount credited to his or her account under the Plan, but not more than the amounts necessary to satisfy such emergency plus amounts necessary to pay taxes reasonably anticipated as a result of the distribution, after taking into account the extent to which such emergency is or may be relieved through reimbursement or compensation by insurance or otherwise or by liquidation of the Eligible Director’s assets (to the extent the liquidation of such assets would not itself cause severe financial hardship).

(4)

ARTICLE VI

AMENDMENT AND TERMINATION OF PLAN

6.1 The Plan may be amended from time to time by resolution of the Committee, but, except to the extent permitted under Section 409A, no such amendment shall permit amounts accumulated pursuant to the Plan prior to the amendment to be paid to an Eligible Director prior to the time he or she would otherwise be entitled hereto.

6.2 The Plan will continue in effect until terminated by resolution of the Committee, but in the event of such termination, the amount accumulated pursuant to the Plan prior to termination will continue to be subject to the provisions of the Plan as if the Plan had not been terminated.

ARTICLE VII

ADMINISTRATION OF THE PLAN

7.1 The Plan shall be administered by the Plan Administrator. The Plan Administrator shall have the power to delegate specific responsibilities to any person or group of persons, and such person or group may serve in more than one such delegated capacity. Such delegations may be to employees of the Company or to other individuals, all of whom shall serve at the pleasure of the Plan Administrator and the Company, and if full-time employees of the Company or an affiliated company, without compensation. Any such person may resign by delivering a written resignation to the Plan Administrator. The Company shall pay all costs of administration of the Plan.

ARTICLE VIII

MISCELLANEOUS

8.1 Nothing contained in the Plan shall be deemed to give any Eligible Director a right to continue as a director of the Company or a Participating Subsidiary. Furthermore, nothing contained in this Plan shall be deemed to create an obligation on the part of the board of directors of the Company or a Participating Subsidiary to nominate any director for re-election.

(5)

8.3 The laws of the State of Hawaii shall govern and control the interpretation and application of the terms of the Plan.

TO RECORD the adoption of this amended and restated Plan, Hawaiian Electric Industries, Inc. has caused this document to be executed this 28 day of October, 2008, effective as of January 1, 2009.


HAWAIIAN ELECTRIC INDUSTRIES, INC.

By		/s/ Patricia U. Wong
		Its Vice President-Administration & Corporate Secretary

(6)

HAWAIIAN ELECTRIC INDUSTRIES, INC.

NON-EMPLOYEE DIRECTORS’ DEFERRED COMPENSATION PLAN

FORM 1 – INITIAL OR REVISED ELECTION FORM

Instructions: This form is used to make an initial deferred compensation contribution and distribution election or revise an existing contribution or distribution election and/or beneficiary designation. If this is an initial deferral election, check the initial election box and complete A B, C and D. If you wish to revise a contribution, check the revised contribution election box and complete E. If you wish to revise your distribution election, check the revised distribution election box and complete F and G. If you only wish to change your beneficiaries, please check the revised designation of beneficiary box and complete that section.

This election will apply to all fees you receive in the future unless you revise or terminate this election no later than December 31 of the year prior to the year you want the revised or terminated election to take effect.

I am a director on the Board of:

Hawaiian Electric Industries, Inc.

Hawaiian Electric Company, Inc.

Maui Electric Company, Limited

Hawaii Electric Light Company, Inc.

American Savings Bank, F.S.B.


Participant Name


Address


Social Security No.						Date of Birth

TO:

HAWAIIAN ELECTRIC INDUSTRIES, INC.

I hereby elect to participate in the Non-Employee Directors’ Deferred Compensation Plan (the “Plan”) of Hawaiian Electric Industries, Inc. (the “Company”) and agree to be bound by the terms and conditions of the Plan.

This election shall apply to the fees denoted which are paid with respect to my services as a director performed on or after January 1, .

I hereby elect to defer receipt of:

% of my retainer fees.

% of my meeting fees.

% of my retainer fees and meeting fees.

I hereby direct that such deferred amounts be paid in:

A lump sum.

Annual installments over a period of years (not more than 10 years).

I hereby direct that the distribution of such deferred amounts commence:


		As of the first business day of the calendar year after I separate from service as a director of the Company (within the meaning of Section 409A of the Internal Revenue Code of 1986, as amended), but not later than age 72.

		As of the first business day of the calendar year after I attain age (not more than age 72).

Subject to the age 72 limitation, payment will not commence until at least five years after initial participation in the Plan.

I hereby direct that in the event of my death prior to the distribution in full of my interest in the Plan that any unpaid balance be paid to:


Name				Relationship



Address



Social Security No.				Date of Birth

(If you name more than one primary beneficiary, each primary beneficiary will share your benefit equally.)


Name				Relationship



Address



Social Security No.				Date of Birth

¨ REVISED CONTRIBUTION ELECTION

I hereby elect to change my contributions to the Non-Employee Directors’ Deferred Compensation Plan (the “Plan”) of Hawaiian Electric Industries, Inc. (the “Company”) and agree to be bound by the terms and conditions of the Plan.

This election shall apply to the fees denoted which are paid with respect to my services as a director performed on or after January 1, .

I hereby elect to defer receipt of:

% of my retainer fees.

% of my meeting fees.

% of my retainer fees and meeting fees.


¨ REVISED DISTRIBUTION ELECTION		(Indicate Years of Deferral to Which this Revised
		Distribution Election Applies: )

I hereby direct that such deferred amounts be paid in:

A lump sum.

Annual installments over a period of years (not more than 10 years).

I hereby direct that the distribution of such deferred amounts commence the first business day of the calendar year: .

¨ REVISED DESIGNATION OF PRIMARY BENEFICIARY

I hereby direct that in the event of my death prior to the distribution in full of my interest in the Plan that any unpaid balance be paid to:


Name				Relationship



Address



Social Security No.				Date of Birth

(If you name more than one primary beneficiary, each primary beneficiary will share your benefit equally.)


Name				Relationship



Address



Social Security No.				Date of Birth

This beneficiary designation revokes any and all other beneficiary designations under the Plan made prior to the date of this designation.

By signing below, I acknowledge that I have read and understood the foregoing.


Signed by		Date
	Director

Receipt acknowledged

Hawaiian Electric Industries, Inc.


By						Date

HAWAIIAN ELECTRIC INDUSTRIES, INC.

NON-EMPLOYEE DIRECTORS’ DEFERRED COMPENSATION PLAN

FORM 2 – TERMINATION OF ELECTION FORM

I am a director on the Board of:

Hawaiian Electric Industries, Inc.

Hawaiian Electric Company, Inc.

Maui Electric Company, Limited

Hawaii Electric Light Company, Inc.

American Savings Bank, F.S.B.


Participant Name



Address



Social Security No.						Date of Birth

TO:

HAWAIIAN ELECTRIC INDUSTRIES, INC.

¨ TERMINATION OF ELECTION

(Indicate Date of Initial and Revised Elections )

Dates

Effective January 1, , I hereby elect to terminate my participation in the Non-Employee Directors’ Deferred Compensation Plan. I understand that all amounts credited to my account under the Plan prior to such effective date of termination will remain subject to the terms and conditions of the Plan and will be paid to me or my beneficiary in accordance with my prior election(s).

By signing below, I acknowledge that I have read and understood the foregoing.


Signed by		Date
	Director

Receipt acknowledged

Hawaiian Electric Industries, Inc.


By						Date

HEI Exhibit 10.6

EXECUTIVE DEATH BENEFIT PLAN OF

HAWAIIAN ELECTRIC INDUSTRIES, INC.

AND PARTICIPATING SUBSIDIARIES

I.	ESTABLISHMENT OF PLAN

Hawaiian Electric Industries, Inc. (“HEI”) hereby restates this Executive Death Benefit Plan of Hawaiian Electric Industries, Inc. and Participating Subsidiaries (“Plan”), effective January 1, 2009. The Plan was originally effective September 1, 2001. The purpose of this restatement is to update the Plan for certain changes in law and to modify the employers included as Participating Employers and certain eligibility and other design features of the Plan. The only benefits provided under this Plan are death benefits. The Plan is a death benefit plan within the meaning of Section 409A(d)(1)(b) of the Internal Revenue Code of 1986, as amended, and the regulations promulgated thereunder, and an unfunded welfare plan maintained for the purpose of providing benefits for a select group of management employees of HEI and certain of its subsidiaries, as described in section 2520.104-24 of the regulations promulgated by the Secretary of Labor pursuant to the Employee Retirement Income Security Act of 1974, as amended. Notwithstanding this restatement, the benefits and eligibility for benefits of any employee who had vested in his or her benefits prior to January 1, 2009 pursuant to Section 4.3 of the Plan, shall be determined under the provisions of the Plan as evidenced by the prior plan document, including, without limitation, any former employee of American Savings Bank, F.S.B. who had so vested.

II.	DEFINITIONS

2.1 “Beneficiary” means the beneficiary designated in writing by a Participant. The Beneficiary designation must be made on a form provided by the Administrative Committee. A Participant must designate his or Beneficiary at the time he or she becomes a Participant, and may change the designated Beneficiary at any time thereafter by executing a new Beneficiary designation. If the designated Beneficiary does not survive the Participant, or if there is no valid Beneficiary designation at the time of the Participant’s death, any benefits payable hereunder shall be paid to the Participant’s estate.

2.2 “Code” means the Internal Revenue Code of 1986, as amended.

2.3 “Committee” means the plan administrator. The plan administrator shall be the Total Compensation Administrative Committee.

2.4 “Compensation Committee” means the Compensation Committee of the Board of Directors of Hawaiian Electric Industries, Inc.

2.5 “Disabled” or “Disability” refers to the existence of a disability within the meaning of the long-term disability program maintained by the Participating Employer by whom a Participant is employed.

2.6 “Eligible Position” means a management position that is designated in the personnel records of the Participating Employer as:

Manager or above at HECO, MECO, or HELCO, or

Grade 50 or above at HEI.

2.7 “ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

2.8 “Participant” means a management employee or former employee of a Participating Employer who has satisfied the eligibility requirements of the Plan, as set forth in Article III below, and has not terminated employment or changed his or her position in a manner that results in a loss of eligibility to participate.

2.9 “Participating Employer” means HEI or one of the following HEI subsidiaries: Hawaiian Electric Company, Inc. (“HECO”); Maui Electric Company, Limited (“MECO”); and Hawaii Electric Light Company, Inc. (“HELCO”).

2.10 “Plan” means the Executive Death Benefit Plan of Hawaiian Electric Industries, Inc. and Participating Subsidiaries, as set forth in this document and as amended from time to time.

2.11 “Retire” or “Retirement” means the voluntary termination of employment with a Participating Employer after the Participant has qualified for immediate commencement of normal or early retirement benefits under the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries (whether or not such Participant actually elects to have such retirement benefits commence immediately).

2.12 “Salary” means base annual rate of salary, including any elective contributions to the Hawaiian Electric Industries Retirement Savings Plan, the Hawaiian Electric Industries, Inc. FlexPlan, or any successor plan thereof, but excluding any incentive compensation, bonuses, deferred compensation, fringe benefits, or other amount not included in base salary.

2.13 “Total Compensation Administrative Committee” means the Hawaiian Electric Industries, Inc. Total Compensation Administration Committee, as organized and operated pursuant to charter adopted on September 18, 2007, as amended from time to time. The Total Compensation Administrative Committee is the plan administrator for this Plan.

III.	ELIGIBILITY

3.1 Becoming a Participant . To become a Participant in the Plan, a person must:

Be employed by a Participating Employer in an Eligible Position on or after the effective date of this Plan; and

Be designated as a Participant in writing by the Committee, or by a member of the Committee to whom the Committee has delegated the authority to designate Participants.

3.2 Forfeiture Upon Termination of Employment . A Participant who terminates employment with the Participating Employers for any reason other than Retirement, death, or Disability shall cease to be a Participant and shall forfeit any and all rights to benefits under this Plan.

3.3 Forfeiture Upon Transfer to Ineligible Position . A Participant who transfers to a position that is not an Eligible Position shall cease to be a Participant and shall forfeit any and all rights to benefits under this Plan.

IV.

BENEFITS

4.1 Preretirement, Postretirement and Disability Death Benefits . A Participant who is employed in, who retired from, or who terminated employment due to Disability from, an Eligible Position, shall receive the following benefits:

If the Participant dies while actively employed, the Participant’s Beneficiary shall receive a lump sum death benefit equal to (i) two times the Participant’s Salary at the date of his or her death, (ii) divided by one minus the highest marginal rate of federal income tax imposed on benefits of this type as of the date of the Participant’s death.

If the Participant dies after he or she Retires, the Participant’s Beneficiary shall receive a lump sum death benefit equal to (i) one times the Participant’s salary at the date of his or her Retirement, (ii) divided by one minus the highest marginal rate of federal income tax imposed on benefits of this type as of the date of the Participant’s death.

If the Participant incurs a Disability, then:

If the Participant dies while still Disabled and before attaining age 65, the Participant’s Beneficiary shall receive a lump sum death benefit equal to (i) two times the Participant’s Salary at the date he or she became Disabled, (ii) divided by one minus the highest marginal rate of federal income tax imposed on benefits of this type as of the date of the Participant’s death.

ii.

If the Participant continues to be Disabled until the time he or she attains age 65, then upon the Participant’s death after such time the Participant’s Beneficiary shall receive a lump sum death benefit equal to (i) one times the Participant’s Salary at the date he or she became Disabled, (ii) divided by one minus the highest marginal rate of federal income tax imposed on benefits of this type as of the date of the Participant’s death.

4.2 Payment . All benefits payable under this Plan shall be paid by the Participating Employer by which the Participant was last employed.

4.3 Vesting . A Participant shall have a vested right to benefits under this Plan upon Retirement. Prior to Retirement, any benefit hereunder shall be subject to forfeiture in accordance with Section 3.2 or Section 3.3; provided, however, that no Participant’s right to benefits may be reduced or eliminated except in accordance with Section 3.2 or Section 3.3 or with the written consent of such Participant.

4.4 Claims Procedure . If any Participant or Beneficiary believes he or she is entitled to a benefit from the Plan which is different from the benefit initially determined, such Participant or Beneficiary may file a written claim for benefits with the Manager-Compensation and Benefits of HECO (or the holder of any successor position, however designated) (the “Manager”). The Manager shall consider such written claim and render a decision within ninety (90) days following receipt thereof. If the Manager denies any part of the claim, he or she shall provide the claimant with written notice of the denial and of the claimant’s right to a further review. The notice shall set forth, in a manner calculated to be understood by the claimant, the reason for the denial and shall refer to specific Plan provisions on which the denial is based and provide a description and explanation of additional information which the claimant might provide to perfect the claim.

Within ninety (90) days after receiving notice that a claim has been denied, the claimant may file a written appeal with the Committee. The claimant may submit written comments, documents, records, and other information relating to the claim. Upon request, the claimant may obtain, free of charge, reasonable access to, and copies of, documents, records, and other information relevant to the claim. The Committee may require the claimant to provide such additional information or testimony as the Committee, in its sole discretion, deems useful or appropriate to its consideration of the claim. In reviewing the claim, the Committee shall take into account all comments, documents, records, and other information submitted by the claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination. The Committee shall render its final decision within sixty (60) days of receipt of the request for reconsideration unless special circumstances require an extension of time. If such an extension is required, the Committee shall provide the claimant with written notice of the extension within the initial sixty (60) day period, and the Committee shall render its decision as soon as possible but in no event later than one hundred twenty (120) days following receipt of the appeal. If the Committee’s final decision is a denial of the claim, the Committee shall provide written notice of the denial, which notice shall set forth, in a manner calculated to be understood by the claimant, the reason for the denial and shall refer to specific Plan provisions on which the denial is based.

Claim determinations by the Manager and the Committee shall be made in their discretion, as provided in Section 5.1. The final decision of the Committee shall be binding and conclusive on all persons.

If the Manager or Committee fails to respond to a claimant within the time limits set forth in this Section, the claimant may consider the claim denied and may pursue whatever additional remedies are available to it. A claimant must comply with these procedures and exhaust all possibilities contained herein before seeking relief in any other forum.

V.	ADMINISTRATION

5.1 Committee’s Power and Discretion . The Committee shall have the power to interpret and construe the provisions of the Plan, to resolve any ambiguities and reconcile any inconsistencies in its provisions, and to decide all questions of fact that arise in the operation of the Plan. All such powers shall be exercised in the Committee’s discretion. Specifically, but without limiting the generality of the foregoing, the Committee shall determine, in its discretion, all questions with respect to any individual’s rights under the Plan, including, but not limited to eligibility for participation, eligibility for and the amount of benefits payable from the Plan, the validity and effect of any Beneficiary designation hereunder, and the proper Beneficiary to whom any benefits hereunder will be paid. The Committee, acting unanimously, shall also have the power to waive the application of Section 3.3 to a Participant if extenuating circumstances exist. The decision of the Committee with regard to the interpretation or construction of the Plan, or on any other matter within its authority, shall be binding and conclusive upon the Participating Employers and upon each Participant, Beneficiary, and any other interested party.

5.2 Delegation . The Committee may delegate authority to one or more of its members, or to any employee of a Participating Employer, in its discretion. In particular, the Committee may delegate authority for the day-to-day administration of the Plan to the Manager-Compensation and Benefits of HECO or such persons in the HECO Benefits Department as such Manager may designate.

VI.	MISCELLANEOUS

6.1 Effect on Prior Deferred Compensation Agreements . This Plan supersedes certain Deferred Compensation Agreements between Participants herein and HEI regarding the payment of death benefits similar to those provided hereunder. Such Deferred Compensation Agreements shall be of no further force or effect. As a condition of participation in this Plan, each Participant who was previously a party to such an agreement shall execute a written revocation of such agreement in a form provided by the Committee. This Plan does not affect Deferred Compensation Agreements that are currently in force between HEI and individuals who do not become Participants in this Plan, including retirees, disabled persons, and certain active employees of the Participating Employers who are not currently employed in Eligible Positions but who were previously employed in such positions and have been permitted to retain the benefit of Deferred Compensation Agreements.

6.2 Amendment and Termination . The Compensation Committee may amend or terminate the Plan at any time in its discretion; provided, however, that no amendment or termination of the Plan shall reduce the rights and benefits of any person who is a Participant at the time of the amendment or termination without such Participant’s written consent. No

amendment or termination of the Plan shall affect benefits that have vested in accordance with Section 4.3.

6.3 No Funding . Benefits shall be paid as needed solely from the general assets of the Participating Employers, insurance contracts whose premiums are paid directly by the Participating Employers from their general assets, or a combination thereof. This Plan shall constitute solely an unsecured promise by the Participating Employers to pay the benefits described herein. Participants and Beneficiaries shall rely solely upon such unsecured promise, and shall have no right, title, interest, or claim to any specific asset, fund, reserve, account, insurance policy, or other property of any nature.

6.4 Life Insurance Policies . The Committee, in its absolute discretion, may purchase or maintain life insurance contracts to assist in meeting the Participating Employers’ benefit obligations hereunder. Any such policies shall be the property of HEI or the Participating Employer purchasing and maintaining such policies. The Administrative Committee shall have the exclusive and unrestricted right to make any elections, exercise any rights, and receive and use any benefits payable thereunder. No Participant or Beneficiary shall have any interest in such policy or any rights thereunder. Each such policy shall be purchased and maintained in accordance with the notice and consent requirements of Section 101(j)(4) of the Code, the insured under each such policy shall be a person described in Section 101(j)(2)(A) of the Code, and notice of each such policy shall be given to the Internal Revenue Service pursuant to Form 8925 or its successor.

6.5 Nonalienation . No benefit payable under this Plan shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, encumbrance, or charge, and any attempt to do so shall be void; nor shall any such benefit be in any manner liable for or subject to the debts, contracts, liabilities, engagements, or torts of, or claims against, any Participant or Beneficiary.

6.6 No Right to Employment . Nothing in this Plan shall give any Participant any right to continued employment with any Participating Employer or limit in any way the Participating Employers’ right to discharge any Participant.

6.7 Indemnification . The Participating Employers shall indemnify and hold harmless their respective directors, officers, employees, and agents, including, without limitation, the members of the Compensation Committee and the Committee, against any and all claims, losses, damages, expenses, and liabilities arising, directly or indirectly, from their responsibilities in connection with the Plan, and from the defense costs thereof (including reasonable attorneys’ fees), to the extent permitted by law and except where any such liability is judicially determined to be the result of gross negligence or willful misconduct. The right of indemnity shall be conditioned upon (1) timely notice to HEI of any claim asserted against a person within the scope of this Section, and (2) the indemnified person’s reasonable cooperation and assistance in the defense of such claim.

6.8 Costs of Enforcement . If the Committee denies a claim for benefits under this Plan, and the claimant is later determined to be entitled to such benefits, then in addition to such

benefits the claimant shall be entitled to recover all costs of enforcing his or her claim, including, without limitation, attorneys’ fees and other legal costs.

6.9 Governing Law . This Plan shall be governed by, and construed and enforced in accordance with, the laws of the State of Hawaii, to the extent such laws are not preempted by ERISA.

TO RECORD the adoption of this Plan, the undersigned have caused this document to be executed this 27 ^th day of October 2008, effective as of January 1, 2009.


HAWAIIAN ELECTRIC INDUSTRIES, INC.

By		/s/ Patricia U. Wong
		Its Vice President-Administration & Corporate Secretary

HEI Exhibit 10.7

AMERICAN SAVINGS BANK

SELECT DEFERRED COMPENSATION PLAN

Restatement Effective January 1, 2009

AMERICAN SAVINGS BANK

SELECT DEFERRED COMPENSATION PLAN

TABLE OF CONTENTS


Article 1. Introduction
1.1	Restatement of Plan	1
1.2	Continuing Effectiveness of 2004 Restatement	1
1.3	Relationship between this Restatement and 2004 Restatement	1
1.4	Purpose of Plan	1

Article 2. Definitions
2.1	Definitions	2
(a)	Account Balance	2
(b)	Affiliate	2
(c)	Asset Purchase Termination	2
(d)	Bank	2
(e)	Beneficiary	2
(f)	Beneficiary Designation Form	2
(g)	Benefit Distribution Date	2
(h)	Board of Directors	2
(i)	Bonus	2
(j)	Change in Control	3
(k)	Claimant	4
(l)	Code	4
(m)	Commissions	4
(n)	Committee	4
(o)	Contributions	4
(p)	Death Benefit	4
(q)	Deferral Agreement	4
(r)	Deferral Contribution Account	5
(s)	Deferral Contributions	5
(t)	Deferral Election	5
(u)	Disability	5
(v)	Disability Benefit	5
(w)	Early Retirement	6
(x)	Elective Contributions	6
(y)	Employer	6
(z)	Enrollment Forms	6
(aa)	ERISA	6
(bb)	Highly Compensated Employee	6
(cc)	Hypothetical Investment	7
(dd)	Interim Distribution	7
(ee)	Interim Distribution Date	7


(ff)	Invest Adjustment(s)	7
(gg)	Investment Allocation and/or Reallocation Election	8
(hh)	Management Employee	8
(ii)	Mid-Year Deferral Election	8
(jj)	Normal Retirement Age	8
(kk)	Participant	8
(ll)	Participation Agreement	9
(mm)	Performance Period	9
(nn)	Plan	9
(oo)	Plan Year	9
(pp)	Regular Deferral Election	9
(qq)	Retirement	9
(rr)	Retirement Benefit	9
(ss)	Salary	10
(tt)	Select Group	10
(uu)	Separation from Service	11
(vv)	Specified Employee	11
(ww)	Termination of Employment Benefit	13
(xx)	Termination of Employment	13
(yy)	Trust	13
(zz)	Unforeseeable Emergency	13

Article 3. Eligibility, Participation and Deferral Elections
3.1	Eligibility	15
(a)	General	15
(b)	Effective Date of Eligibility for Newly Eligible Employees	15
(c)	Newly Eligible Employees	15
(d)	Breaks in Eligibility	15
(e)	Continuing Eligibility	15
3.2	Participation	15
3.3	Deferral Elections	16
(a)	General	16
(b)	Elements of Deferral Elections	16
(c)	How Made	16
(d)	Types of Deferral Elections, When Made and When Effective	16
(e)	Types of Compensation to which Deferral Elections are Applicable and How Applied	17

Article 4. Contributions, Investment Adjustments and Taxes
4.1	Deferral Contributions	20
(a)	General	20
(b)	Determination of Deferral Contributions	20
(c)	Minimum and Maximum Deferrals	20
4.2	Selection of Hypothetical Investments	20
4.3	Adjustment of Participant Accounts	20
4.4	Taxes	21
(a)	Annual Withholding from Compensation	21


(b)	Payment of Taxes from Deferral Contribution Account	21
(c)	Withholding from Benefit Distributions	21
(d)	Payment upon Income Inclusion under Section 409A	22
4.5	Vesting	22

Article 5. Cancellation of Deferral Elections
5.1	General	23
5.2	Unforeseeable Emergencies and Hardship Distributions	23
5.3	Disability	23

Article 6. Distributions
6.1	Interim Distributions	24
(a)	Time and Form of Payment	24
(b)	Earlier Occurrence of Benefit Distribution Date	24
6.2	Distributions due to Unforeseeable Emergencies	24
(a)	General	24
(b)	Amount of Distribution	24
(c)	Time and Form of Payment	25
6.3	Benefit Distribution Date	25
6.4	Distributions on Termination of Employment	25
(a)	Time and Form of Payment	25
(b)	Death Prior to Payment of Termination Benefit	25
6.5	Distributions on Retirement	25
(a)	Time and Form of Payment of Retirement Benefit	25
(b)	Death Prior to Completion of Retirement Benefit	26
6.6	Distributions on Death; Time and Form of Payment	26
6.7	Distributions on Disability	26
(a)	Time and Form of Payment	26
(b)	Eligibility for Retirement	26
6.8	Payment by March 15 ^th Deemed Timely	26
6.9	Distributions to Specified Employees on Retirement or Termination of Employment	27

Article 7. Beneficiary Designation
7.1	Beneficiary	28
7.2	Beneficiary Designation; Change	28
7.3	Acknowledgment	28
7.4	No Beneficiary Designation	28
7.5	Discharge of Obligations	28

Article 8. Termination, Amendment or Modification
8.1	Termination	29
8.2	Amendment	30
8.3	Effect of Payment	31

Article 9. Administration
9.1	Committee	32

iii


9.2	Agents	32
9.3	Binding Effect of Decisions	32
9.4	Indemnity of Committee	32
9.5	Employer Information	32

Article 10. Claims Procedures
10.1	Presentation of Claim	33
10.2	Decision on Claim	33
10.3	Notification of Decision	33
10.4	Review of a Denied Claim	33
10.5	Decision on Review	34
10.6	Preservation of Other Remedies	34
10.7	Administrative Exhaustion	34

Article 11. Trust
11.1	Establishment of the Trust	35
11.2	Relationship of the Plan and the Trust	35
11.3	Distributions from the Trust	35
11.4	No Offshore Trust	35

Article 12. Miscellaneous
12.1	Status of the Plan	36
12.2	Unsecured General Creditor	36
12.3	Employer’s Liability	36
12.4	Nonassignability	36
12.5	Not a Contract of Employment	36
12.6	Furnishing Information	36
12.7	Terms	37
12.8	Captions	37
12.9	Governing Law	37
12.10	Notice	37
12.11	Successors	37
12.12	Validity	37
12.13	Incompetent	37
12.14	Insurance	38

Exhibit A

AMERICAN SAVINGS BANK

SELECT DEFERRED COMPENSATION PLAN

(Restatement Effective January 1, 2009)

ARTICLE 1. INTRODUCTION

1.1 Restatement of Plan . AMERICAN SAVINGS BANK, F.S.B. (the “Bank”), hereby restates the American Savings Bank Select Deferred Compensation Plan (the “Plan”). Except as otherwise noted, this restatement (“Restatement”) is effective as of the Plan Year commencing January 1, 2009 for all amounts deferred after December 31, 2004. This Restatement is intended to comply with the provisions of Section 409A of the Internal Revenue Code (“Code”) and the regulations promulgated thereunder. For the period between December 31, 2004 and January 1, 2009, this Plan has been operated in good faith compliance with Section 409A and such regulations.

1.2 Continuing Effectiveness of 2004 Restatement . The Plan was originally effective May 1, 2000 and restated on September 22, 2004 (the “2004 Restatement”). The 2004 Restatement, as set forth in Exhibit A to this Plan, shall be maintained as a separate and distinct portion of the Plan and shall remain effective for all amounts deferred prior to January 1, 2005, together with net earnings thereon. Such amounts shall include Bonus that was payable in 2005 with respect to services performed in 2004 and that was credited to Participants’ Deferral Contribution Accounts in 2005 pursuant to deferral elections validly made in 2004 under the 2004 Restatement.

1.3 Relationship between this Restatement and 2004 Restatement . The intention of maintaining the 2004 Restatement as a separate portion of the Plan is to “grandfather” deferrals made prior to January 1, 2005 as permitted by Section 409A of the Code and the Treasury Regulations promulgated thereunder. Accordingly, deferrals subject to the provisions of this Restatement and deferrals subject to the provisions of the 2004 Restatement shall be accounted for separately and shall be treated as benefits arising under separate portions of the Plan. In furtherance of such treatment, the term, “Plan,” shall hereinafter be reserved to refer only to the portion of the Plan as it exists under this Restatement, and the term, “2004 Plan,” shall refer only to the portion of the Plan as it continues to exist under the 2004 Restatement. In no event shall an amendment to the Plan materially enhance benefits or rights existing as of October 3, 2004 under the 2004 Restatement or add a new material benefit or right affecting amounts earned and vested before January 1, 2005, except as may be permitted under Section 1.409A-6(a)(4) of the Treasury Regulations or its successor.

1.4 Purpose of Plan . The purpose of the Plan is to provide Participants an opportunity to defer compensation that would otherwise be currently payable to them. The Plan is intended to be an unfunded plan for a select group of management or highly compensated employees within the meaning of Sections 201(2), 301(a)(3), and 401(a)(1) of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”).

ARTICLE 2. DEFINITIONS

2.1 For purposes of this Plan, the following phrases or terms shall have the meanings indicated:

(a)

“Account Balance” shall mean, as of any given date called for under the Plan, the balance of the Participant’s Deferral Contribution Account as such account has been adjusted to reflect all applicable Investment Adjustments and all prior withdrawals and distributions in accordance with Article 4 of the Plan.

(b)

“Affiliate” shall mean any corporation or other entity or business that is required to be treated as a single employer with the Bank under Section 414 of the Code.

(c)

“Asset Purchase Termination” shall mean a Termination of Employment with the Employer owing to a transfer of employment incident to the sale or other transfer of substantial assets by the Employer, such as a plant or division or substantially all the assets of a trade or business, to an unrelated buyer in a bona fide, arm’s length transaction, provided that all employees whose employment is transferred from the Employer to the unrelated buyer are consistently treated for purposes of any applicable nonqualified deferred compensation plan and the treatment of such transfer of employment as a Termination of Employment is specified in writing by the parties to the asset purchase transaction no later than the closing date of that transaction.

(d)

“Bank” shall mean American Savings Bank, F.S.B., and any successor.

(e)

“Beneficiary” shall mean one or more persons, trusts, estates or other entities designated by the Participant in accordance with Article 7 to receive the Participant’s undistributed Account Balance in the event of the Participant’s death.

(f)

“Beneficiary Designation Form” shall mean the document which shall be used by the Participant to designate the Participant’s Beneficiary for the Plan.

(g)

“Benefit Distribution Date” shall mean the date on which distribution of the Participant’s Account Balance is triggered due to Termination of Employment, Retirement, death, or Disability.

(h)

“Board of Directors” shall mean the board of directors of the Bank.

(i)

“Bonus” shall mean performance based compensation payable under any plan or arrangement sponsored by the Employer or an Affiliate that is eligible for deferral under this Plan. “Performance based compensation” is any compensation, the amount of which or the entitlement to which, is contingent on the satisfaction of organizational or individual performance criteria relating to a performance period of at least twelve (12) consecutive months. Performance based compensation is

“eligible for deferral under this Plan” if the relevant organizational or individual performance criteria are pre-established, and the compensation has been so designated by the Committee. Organizational or individual performance criteria are considered pre-established if established in writing by not later than ninety (90) days after the commencement of the period of service to which the criteria relate, provided that the outcome of the application of the criteria is substantially uncertain at the time that the criteria are established. Bonus does not include any amount or portion of any amount that will be paid either regardless of performance, or based upon a level of performance that is substantially certain to be met at the time the criteria are established. Bonus shall not include Salary, Commissions, stock-related awards and other non-monetary incentives, and such other incentive items as may be excluded from the definition of “Bonus” by the Committee in its sole discretion. As of the date of this Restatement, and subject to the decisions of the Committee from time-time-time, Bonus includes, but is not limited to, compensation payable under the Executive Incentive Compensation Plan (“EICP”) and the Performance Bonus Plan (“PBP”), provided that such compensation otherwise meets the requirements of this definition, and further provided that Special Recognition Awards or awards paid on multi-year performance periods under the PBP are excluded. Without limiting the programs and types of other performance based compensation excluded from Bonus, “Bonus” excludes compensation payable under the Hawaiian Electric Industries, Inc. Long Term Incentive Plan.

(j)

“Change in Control” shall mean the earliest to occur of the following dates:

(1)

a change in ownership, defined as the acquisition by any one person (or more than one person acting as a group) of stock of the Bank that, together with stock held by such person or group, constitutes more than fifty percent (50%) of the total fair market value or total voting power of the stock of the Bank;

(2)

a change in effective control, defined as the acquisition during any 12-month period by any one person (or more than one person acting as a group) of stock of the Bank comprising thirty percent (30%) or more of the total voting power of the stock of the Bank, or the replacement, during any 12-month period, of a majority of the members of the Board of Directors with directors whose appointment or election is not endorsed by the majority of the members of the Board of Directors before the date of such appointment or election; and

(3)

a change in ownership of a substantial portion of the Bank’s assets, defined as the acquisition by any one person (or more than one person acting as a group) during the 12 month period ending on the date of the most recent acquisition by such person or persons, of assets of the Bank that have a total gross fair market value equal to or more than forty percent (40%) of the total gross fair market value of all of the assets of the Bank

immediately before such acquisition or acquisitions (determined without regard to any liabilities associated with such assets).

Whether a Change in Control has occurred for purposes of this Plan shall be determined in accordance with the provisions of Section 409A-3(i)(5) of the Treasury Regulations or its successor. A Change in Control with respect to the Bank shall be deemed to occur if the majority shareholder of the Bank experiences a Change in Control as defined in (1), (2) or (3), above.

(k)

“Claimant” shall mean the person or persons described in Section 10.1 who apply for benefits or amounts that may be payable under the Plan.

(l)

“Code” shall mean the Internal Revenue Code of 1986, as amended. References to the Code shall include references to any successor section or provision of the Code.

(m)

“Commissions” shall mean compensation or portions of compensation earned by an employee that is based upon the direct sale of a product or a service to a customer unrelated to either the Employer or the employee, that consists of either (i) a portion of the purchase price for the product or service or (ii) an amount, substantially all of which is calculated by reference to the volume of sales, and for which payment is contingent upon the employee’s (or Employer’s or other unrelated third party’s) receiving payment from the customer for the product or service. For purposes of this Plan, an employee earning Commissions is treated as providing the services to which such Commissions relate in the year in which the customer remits payment for such product or service.

(n)

“Committee” shall mean the Hawaiian Electric Industries, Inc. Total Compensation Administrative Committee, as organized and operated pursuant to charter adopted on September 18, 2007, as the same may be amended from time to time.

(o)

“Contributions” shall refer, collectively, to any and all Deferral Contributions.

(p)

“Death Benefit” shall mean the benefit set forth in Section 6.6.

(q)

“Deferral Agreement” shall mean a form prescribed by the Committee pursuant to which a Participant may elect to defer, with respect to a Performance Period, receipt of a certain percentage of Salary, Bonus or Commissions to be earned in the Performance Period and to contribute such percentage of such items of compensation to the Plan as Deferral Contributions. At the same time as the Deferral Agreement is made, and as part of making such agreement, the Participant shall specify the form in which such Deferral Contributions shall be distributed in the event of Retirement. The Participant shall also have the option in the Deferral Agreement of specifying that a percentage of such Deferral Contributions shall be distributed in a lump sum upon an Interim Distribution

Date selected by the Participant, rather than upon the Benefit Distribution Date. A Deferral Agreement shall be made and become irrevocable in accordance with Section 3.3 and is effective only if timely made. As of the date of this Restatement, the Plan recognizes Salary Deferral Agreements, Commissions Deferral Agreements and Bonus Deferral Agreements.

(r)

“Deferral Contribution Account” shall mean an account to record a Participant’s aggregate Deferral Contributions, as adjusted for Investment Adjustments and any distributions. The Deferral Contribution Account shall be utilized solely as a device for the measurement of amounts to be paid to the Participant under the Plan. The Deferral Contribution Account shall not constitute or be treated as an escrow, trust fund, or any other type of funded account for purposes of the Code or ERISA, and contingent amounts credited thereto shall not be considered “plan assets” for ERISA purposes. The Deferral Contribution Account merely provides a record of the bookkeeping entries relating to the contingent benefits that the Employer promises to pay to a Participant and shall thus constitute merely an unsecured promise to pay such amounts in the future

(s)

“Deferral Contributions” shall mean the amounts of Salary, Commissions and Bonus deferred by a Participant with respect to a Plan Year and “credited” to the Participant’s Deferral Contribution Account, and shall include Investment Adjustments thereon. Deferral Contributions shall be deemed to be made to the Plan by the Participant on the dates on which the Participant would have received such compensation had it not been deferred pursuant to the Plan and shall be allocated to Hypothetical Investments pursuant to the Participant’s then effective Investment Allocation and/or Reallocation Election as soon as administratively feasible.

(t)

“Deferral Election” shall mean a Participant’s act of timely completing and filing a Deferral Agreement with the Committee. Except as otherwise provided in Article 5, a Deferral Election with respect to a Performance Period is irrevocable, and, except in the case of Special Bonus Deferral Elections, a Deferral Election must be made before the first day of the Performance Period.

(u)

“Disability” shall mean that the Participant is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than 12 months. The Participant shall be deemed to have a Disability if the Participant is determined to be totally disabled by the Social Security Administration or if the Participant is, by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, receiving income replacement benefits for a period of not less than three months under an accident and health plan covering employees of the Employer.

(v)

“Disability Benefit” shall mean the benefit set forth in Section 6.7.

(w)

“Early Retirement” shall mean retirement on the date on which a Participant attains age 55 or on any date after such date and prior to the Participant’s attainment of Normal Retirement Age.

(x)

“Elective Contributions” shall mean reductions of a Participant’s Salary, Commissions or Bonus for amounts voluntarily deferred by the Participant pursuant to any qualified or nonqualified deferred compensation or welfare or fringe benefit plan, including, without limitation, amounts deferred pursuant to Code Sections 125, 132(f), 402(e)(3) and 402(h), provided, however, that all such amounts would have been payable to the Participant in cash had there been no such deferral. Elective Contributions shall be deemed to include any amounts not available to a participant in cash under a 125 plan in lieu of group health coverage because the Participant is unable to certify that he or she has other health coverage, provided that the Employer does not request or collect information regarding Participants’ other health coverage as part of the enrollment process for group health coverage except to the extent required to satisfy legal requirements imposed by the State of Hawaii pursuant to the Prepaid Health Care Act.

(y)

“Employer” shall mean the Bank and any Affiliate that has been selected by the Board of Directors to participate in the Plan and has adopted the Plan.

(z)

“Enrollment Forms” shall mean the Participation Agreement, the Deferral Agreement(s), the Beneficiary Designation Form, the Investment Allocation and/or Reallocation Election and any other forms or documents which may be required of a Participant by the Committee, in its sole discretion, as a condition of participating in the Plan.

(aa)

“ERISA” shall mean the Employee Retirement Income Security Act of 1974, as amended. References herein to any section of ERISA shall include references to any successor section or provision of ERISA.

(bb)

“Highly Compensated Employee” with respect to a Plan Year (the “Eligibility Year”) shall mean an employee whose W-2 compensation for the preceding Plan Year is equal to at least 120% of the taxable wage base for that year and whose compensation is not expected to decline below 120% of the taxable wage base in the Eligibility Year. If the “preceding Plan Year” for purposes of the preceding sentence has not yet been completed, then W-2 compensation for the preceding Plan Year shall be projected, if necessary, on the basis of any reasonable method. For example, in the case of elections required to be made by continuing Participants prior to the first day of the Plan Year pursuant to Section 3.3(d)(ii), “Highly Compensated Employees” shall mean employees who, as of the date of Deferral Elections made pursuant to Section 3.3(d)(ii), either have earned or are reasonably projected to earn W-2 compensation that is equal to at least 120% of the taxable wage base for the year in which the elections are made and whose compensation is not expected to decline below 120% of the taxable wage base in

the Eligibility Year. In the case of an employee who was or will have been employed for less than twelve months in the Plan Year preceding the Eligibility Year, the employee’s W-2 compensation shall be annualized by multiplying the employee’s actual or projected compensation for such year times a fraction, the denominator of which is the employee’s months of employment in the preceding Plan Year (including fractional months) and the numerator of which is twelve. In the case of an employee who was not employed by the Employer in the preceding Plan Year, the employee’s projected W-2 compensation from the Employer for the Eligibility Year and the taxable wage base for such year shall be employed for purposes of the rule stated in the first sentence of this Section. Notwithstanding anything to the contrary in this Section, eligibility to participate in the Plan is not established merely by meeting the definition of “Highly Compensated Employee” but is subject to all provisions of this Plan, including selection for eligibility by the Bank, in its sole discretion, pursuant to Section 3.1(a) of the Plan. The Committee may prescribe rules different from those stated in this Section for the determination of “Highly Compensated Employee,” provided, however, that, in the reasonable opinion of the Committee, such rules satisfy the requirements of Sections 201(2), 301(a)(3), and 401(a)(1) of ERISA.

(cc)

“Hypothetical Investment” shall mean an investment fund or benchmark made available to Participants by the Committee for the purpose of valuing Deferral Contribution Accounts.

(dd)

“Interim Distribution” shall mean the benefit distributed on an Interim Distribution Date.

(ee)

“Interim Distribution Date” shall mean a date selected by the Participant on which a designated portion of Deferral Contributions attributable to a Plan Year shall be distributed to the Participant in a lump sum payment, provided that an Interim Distribution Date shall be the first day of a Plan Year and may not occur sooner than the fifth anniversary of the first day of the Plan Year with respect to the which the Deferral Election is made. An Interim Distribution Date may be selected only at the time that the Participant makes a Deferral Election with respect to a Plan Year and becomes irrevocable when the Deferral Election becomes irrevocable.

(ff)

“Investment Adjustment(s)” shall mean any appreciation credited to a Participant’s Deferral Contribution Account as income or gains, or depreciation deducted from such Account as losses, in accordance with such Participant’s selection of Hypothetical Investments pursuant to the Participant’s currently effective Investment Allocation and/or Reallocation Election. Investment Adjustments shall be determined with respect to a period on the basis of the total rate of return (including increases or decreases in fair market value) that would apply if the Participant’s Deferral Contribution Account had actually been invested in the Hypothetical Investments selected by the Participant. An Investment Adjustment may be made in relation to a Hypothetical Investment

only with respect to the period after the Hypothetical Investment was selected by the Participant. Investment Adjustments shall be shall be made at least once annually and shall be treated as being included in a Participant’s Deferral Contributions and subject to the same Deferral Election as the Participant’s Deferral Contributions.

(gg)

“Investment Allocation and/or Reallocation Election” shall mean a form prescribed by the Committee pursuant to which a Participant shall allocate or reallocate Deferral Contributions to Hypothetical Investments. An Investment Allocation and/or Reallocation Election shall apply with respect to all new Deferral Contributions made to the Plan after the effective date of the Election but prior to the timely filing of a subsequent Election. A new Investment Allocation and/or Reallocation Election may be filed by the Participant electronically, telephonically, in a writing on paper or by such other means as may be prescribed by the Committee, on a monthly or such other basis as the Committee may determine. Provided that such filing is timely and otherwise proper, it shall be given effect as soon as administratively feasible. An Investment Allocation and/or Reallocation Election shall be deemed timely if submitted to the Committee in accordance with the procedures and deadlines established by the Committee.

(hh)

“Management Employee” with respect to a Plan Year shall mean an employee, who, in the reasonable opinion of the Committee, possesses duties and responsibilities at management level and above. An employee at the level of Vice President and above shall be presumed to be a Management Employee for purposes of this definition so long as the employee possesses duties and responsibilities which, in substance, are consistent with his or her title. Notwithstanding anything to the contrary in this Section, eligibility to participate in the Plan is not established merely by meeting the definition of “Management Employee” but is subject to all provisions of this Plan, including selection for eligibility by the Bank, in its sole discretion, pursuant to Section 3.1(a) of the Plan. The Committee may prescribe rules different from those stated in this Section for the determination of “Management Employee,” provided, however, that, in the reasonable opinion of the Committee, such rules satisfy the requirements of Sections 201(2), 301(a)(3), and 401(a)(1) of ERISA.

(ii)

“Mid-Year Deferral Election” shall mean a Deferral Election made on or after the first day of the Plan Year.

(jj)

“Normal Retirement Age” shall mean age 65.

(kk)

“Participant” shall mean any employee who is selected to participate in the Plan in accordance with Section 3.1, who elects to participate in the Plan, and who makes a timely Deferral Election. “Participant” shall include a current employee who has a Deferral Contribution Account in the Plan but is not entitled to, or has

elected not to, make new deferrals to the Plan and a former employee entitled to receive benefits under the Plan.

(ll)

“Participation Agreement” shall mean the separate written agreement entered into by the Bank and the Participant, which shall indicate the Participant’s intent to defer compensation subject to the terms of the Plan and the Participation Agreement.

(mm)

“Performance Period” shall mean the Plan Year or portion thereof in which rights to compensation earned by the Participant are subject to a Deferral Election under this Plan. Such Plan Year is the Plan Year next following a Regular Deferral Election, the Plan Year in which a Special Bonus Deferral Election is made, or so much of the Plan Year as remains after the effective date of a Mid-Year Deferral Election. The determination of the Performance Period is subject to the following distinctions:

(i)

for Salary, the Performance Period is the Plan Year in which compensable services are performed and in which payment for such services is made, provided, however, that Salary earned in the final payroll period of a Plan Year but not paid until the first payday of the next Plan Year, is deemed to be earned in the next Plan Year;

(ii)

for Commissions, the Performance Period is deemed to be the Plan Year in which the Commissions are paid;

(iii)

for Bonus, the Performance Period is the Plan Year in which compensable services are performed, even though the Bonus is awarded and is payable in a later year.

(nn)

“Plan” shall mean the American Savings Bank Select Deferred Compensation Plan, as described herein, subject to amendment from time to time.

(oo)

“Plan Year” shall mean the period beginning on January 1 ^st of each year and ending December 31 ^st .

(pp)

“Regular Deferral Election” shall mean any Deferral Election that is not a Mid-Year Deferral Election or a Special Bonus Deferral Election. A Regular Deferral Election occurs in an enrollment period designated by the Committee and ending prior to the start of the Performance Period.

(qq)

“Retirement” shall mean, with respect to an employee, Separation from Service on any Early Retirement date or on or after the attainment of Normal Retirement Age for any reason other than death and shall not include an authorized leave of absence. For purposes of benefit payments, an employee who separates from service on account of Disability after attaining Normal Retirement Age or fulfilling the requirements for Early Retirement shall be deemed to have retired. To “retire” (uncapitalized) shall refer to the act of making a Retirement.

(rr)

“Retirement Benefit” shall mean the benefit set forth in Section 6.5.

(ss)

“Salary” shall mean the annual compensation payable to an employee by the Bank for services rendered during a Plan Year and required to be set forth in Box 1 of the employee’s W-2 for the Plan Year before reduction for any Elective Contributions, provided, however, that Salary shall not include:

(i)

Bonus,

(ii)

Commissions,

(iii)

contributions to any employee benefit plan (other than Elective Contributions),

(iv)

the value of stock options or other equity compensation,

(v)

amounts paid under the Hawaiian Electric Industries, Inc. Long-Term Incentive Plan,

(vi)

amounts paid to or on behalf of the employee for fringe benefits such as (but not limited to) group life and health insurance, automobile allowance, club memberships and dues, or expense reimbursements, regardless of whether such benefits are taxable to the employee,

(vii)

separation pay or benefits payable through a window program,

(viii)

parachute payments,

(ix)

distributions to or income required to be recognized by the employee during a Plan Year under this Plan or any qualified or other nonqualified deferred compensation plan of the Employer, including, without limitation, distributions from this Plan made on an Interim Distribution Date, and

(x)

“imputed income,” including, but not limited to, employee income arising from relief from indebtedness or employer payment of taxes or other obligations of the employee.

(tt)

“Select Group” for purposes of the phrase, “Select Group of Management or Highly Compensated Employees,” means a group of employees, each of whom is a Management Employee or Highly Compensated Employee, who have been designated as eligible to participate in this Plan by the Committee pursuant to Section 3.1(a) hereof, and whose total number does not exceed twelve per cent (12%) of the Bank’s total workforce, considering all of such eligible employees and not only those who elect to participate in this Plan. Upon good cause and to the extent permissible under applicable law, including ERISA, the Committee may grant exceptions to the foregoing limitation on the total number of employees who may be designated as members of the Select Group, provided that the total number of employees so designated shall in no event exceed fifteen percent (15%) of the Bank’s total workforce or such other limit on participation as may be applicable under ERISA, U.S. Department of Labor or Treasury Regulations, or judicial determination. The Committee, in its sole discretion, shall adopt whatever rules it may deem necessary, appropriate, or desirable to maintain the Select Group within the applicable size limitation, including, but not limited to, giving preference for eligibility to continuing Participants, Management Employees, or Highly Compensated Employees, or ranking employees within subgroups or within the Select Group by compensation, title, longevity, or any

other variable deemed relevant by the Committee. For purposes of this section, “Bank’s total workforce” shall be broadly construed, including all common law, casual, contract, and leased employees. The Committee may prescribe rules different from those stated in this Section for the determination of “Select Group,” provided, however, that, in the reasonable opinion of the Committee, such rules satisfy the requirements of Sections 201(2), 301(a)(3), and 401(a)(1) of ERISA. Notwithstanding anything to the contrary in this Section, eligibility to participate in the Plan is not established merely by being includable in a Select Group but is subject to all provisions of this Plan, including selection for eligibility by the Bank, in its sole discretion.

(uu)

“Separation from Service” shall mean a termination of the employment relationship with the Employer on account of death, Disability, Retirement or other Termination of Employment. The employment relationship is treated as continuing and the employee will not be deemed to have separated from service while the employee is on military leave, sick leave, or other bona fide leave of absence if the period of such leave does not exceed six months or, if longer, so long as the employee retains a right to reemployment with the Employer under an applicable statute or by contract. For purposes of this rule, a leave of absence constitutes a bona fide leave of absence only if there is a reasonable expectation that the employee will return to perform services for the Employer. If the period of leave exceeds six months and the employee does not retain a right to reemployment under an applicable statute or by contract, the employment relationship is deemed to terminate on the first date immediately following such six-month period.

(vv)

“Specified Employee” shall mean an employee who meets the requirements of the Default Specified Employee Rule, unless the Bank and its Affiliates have adopted a Controlled Group Specified Employee Rule. In the latter event, “Specified Employee” shall mean an employee who meets the requirements of the Controlled Group Specified Employee Rule.

(i)

Default Specified Employee Rule . An employee meets the requirements of the Default Specified Employee Rule if, as of the date of the employee’s Separation from Service, the employee is a key employee of Hawaiian Electric Industries, Inc., or, if stock of Hawaiian Electric Industries, Inc. is not then publicly traded, of the Bank or any Affiliate, if the stock of such person is then publicly traded. An employee is a “key employee” for purposes of this definition if the employee meets the requirements of Section 416(i)(1)(A)(i), (ii), or (iii) of the Code (applied in accordance with the regulations thereunder and disregarding Section 416(i)(5)) at any time during the 12-month period ending on a specified employee identification date. An employee described by the preceding sentence shall be treated as a Specified Employee for the entire 12-month period beginning on the specified employee effective date.

(A)

Definition of Compensation . For purposes of the Default Specified Employee Rule the definition of compensation under Section 1.415(c)-2(a) of the Treasury Regulations shall be used, applied as if the Employer were not using any safe harbor provided in Section 1.415(c)-2(d), any of the special timing rules provided in Section 1.415(c)-2(e), and any of the special rules provided in Section 1.415(c)-2(g).

(B)

Specified Employee Identification Date . The specified employee identification date is December 31 ^st .

(C)

Specified Employee Effective Date . The specified employee effective date is the first day of the fourth month following the specified employee identification date.

(D)

Corporate Transactions .

(I)

Mergers and Acquisitions of Public Companies . If the Employer merges with another company, stock of which is publicly traded, or acquires or is acquired by such a company, the next specified employee identification date and next specified employee effective date shall be those of the survivor or acquirer. For the period preceding such dates, Specified Employees shall be the top 50 employees (including any 1% or 5% owners described in Section 416(i)(1)(ii) or (iii) of the Code) of the combined Specified Employee lists of the merged and surviving or acquired and acquiring companies, ranked in terms of compensation or otherwise reasonably determined.

(II)

Mergers and Acquisitions Involving Non-Public Companies . In a merger or acquisition involving the Employer and a company that is not publicly traded or, if neither the Employer nor an Affiliate is then publicly traded, the Employer and a publicly traded company, the next specified employee identification date and next specified employee effective date shall be those that the publicly traded company involved in the transaction would have been required to use absent the transaction. For the period preceding such dates, “Specified Employees” shall continue to be the Specified Employees of the company that was publicly traded prior to the transaction.

(III)

Spinoffs . If the Employer spins off a subsidiary or business operations that become publicly traded and the Employer or any Affiliate remains publicly traded, then the next

specified employee identification date and next specified employee effective date of each of the Employer and the spun off entity shall be those that would have applied to the Employer absent the spinoff. For the period preceding such dates, “Specified Employees” shall continue to be the employees who were the pre-spinoff Specified Employees of the Employer.

(IV)

Definitions of Terms . For purposes of terms used in this Subsection (D), the definitions under Section 1.409A-1(i) of the Treasury Regulations, or its successor, shall apply.

(E)

Nonresident alien employees . For purposes of determining whether an employee is a key employee, Section 1.415(c)-2(g)(5) applies. Therefore, compensation for purposes of such determination shall include compensation excludible from an employee’s gross income due to the location of the services or the identity of the employer.

(ii)

Controlled Group Specified Employee Rule . Employers are permitted to make certain elections under Sections 1.409A-1(i)(2)-(7) of the Treasury Regulations with respect to the determination of Specified Employees. Such elections made by the Employer or any Affiliate, including Hawaiian Electric Industries, Inc., with respect to the determination of Specified Employees shall be effective for the determination of Specified Employees under this Plan, and the Default Specified Employee Rule shall not apply, as of the date that all necessary corporate actions have been taken by the Bank and all Affiliates of the Bank to make such elections binding upon this Plan and all nonqualified deferred compensation plans of the Bank and any Affiliate which include, as participants, employees who would become Specified Employees owing to the application of such elections. Otherwise, the Default Specified Employee Rule shall apply.

(ww)

“Termination of Employment Benefit” shall mean the benefit set forth in Section 6.4.

(xx)

“Termination of Employment” shall mean a voluntary or involuntary Separation from Service for any reason other than Retirement, Disability or death. Terminations of Employment include Asset Purchase Terminations.

(yy)

“Trust” shall mean a grantor trust which meets the requirements of Revenue Procedure 92-64, 1992-2 C.B. 422, or successor authority and is commonly referred to as a “rabbi trust.”

(zz)

“Unforeseeable Emergency” shall mean a severe financial hardship to the Participant resulting from an illness or accident of the Participant, the

Participant’s spouse or beneficiary, or the Participant’s dependent (as defined in Section 152 of the Code, without regard to Sections 152(b)(1), (b)(2) or (d)(1)(B)); loss of the Participant’s property due to casualty (including the need to rebuild a home following damage to a home not otherwise covered by insurance, for example, not as a result of a natural disaster); or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Participant. For example, the imminent foreclosure of or eviction from the Participant’s primary residence may constitute an unforeseeable emergency. In addition, the need to pay for medical expenses, including non-refundable deductibles, as well as for the costs of prescription drug medication, may constitute an unforeseeable emergency. Finally, the need to pay for the funeral expenses of a spouse, a beneficiary, or a dependent (as defined in Section 152, without regard to Section 152(b)(1), (b)(2), or (d)(1)(B)) may also constitute an unforeseeable emergency. Except as otherwise provided in this Section, the purchase of a home and the payment of college tuition are not unforeseeable emergencies.

ARTICLE 3. ELIGIBILITY, PARTICIPATION AND DEFERRAL ELECTIONS

3.1 Eligibility .

(a)

General . Employees who are determined by the Bank to be includable in a Select Group of Management or Highly Compensated Employees of the Bank and are specifically approved for participation by the Bank, in its sole discretion, shall be eligible to make Deferral Elections under this Plan. Continued eligibility to make Deferral Elections, year-by-year, shall be conditioned upon a Participant’s continuing to meet the requirements of the Plan, including, but not limited to, continuing to be includable in a Select Group of Management or Highly Compensated Employees of the Bank.

(b)

Effective Date of Eligibility for Newly Eligible Employees . The effective date of eligibility for a newly eligible employee shall be either the date on which the employee is given notice of eligibility to participate by the Committee or, in the discretion of the Committee, the date of commencement of the enrollment period for Regular Deferral Elections for the Plan Year next following the date on which the employee is given notice of eligibility to participate.

(c)

Newly Eligible Employees . An employee who first becomes eligible to participate in the Plan with respect to a Plan Year that either has already commenced or will commence in 30 days or less shall be entitled to make a Mid-Year Deferral Election. All other newly eligible employees shall participate in the Plan through Regular Deferral Elections. For purposes of this rule, an employee who, prior to the effective date of the employee’s eligibility to participate in this Plan, is eligible to participate in a nonqualified deferred compensation plan of the Employer or any Affiliate that is an elective account plan shall not be deemed to be a newly eligible employee and shall not be entitled to make a Mid-Year Deferral Election.

(d)

Breaks in Eligibility . If a Participant ceases to be eligible to participate in the Plan (other than through accrual of earnings) and subsequently becomes eligible to participate again, the employee shall be treated as being a newly eligible employee if the employee had not been eligible to participate in the Plan (other than through accrual of earnings) at any time during the 24-month period ending on the effective date of the employee’s eligibility to participate.

(e)

Continuing Eligibility . An employee is deemed to be eligible to participate in the Plan with respect to any Performance Period for which the employee is or was eligible to make a Deferral Election, regardless of whether the employee makes such a Deferral Election.

3.2 Participation . To initiate participation in this Plan or to continue participation with respect to a new Plan Year, a newly eligible employee or a continuing Participant shall make a Deferral Election in accordance with the requirements of this Plan.

3.3 Deferral Elections .

(a)

General . A Deferral Election shall be made within the period established by the Committee, provided that, except in the case of Special Bonus Deferral Elections, a Deferral Election must be made, and shall become irrevocable, no later than the end of the day before the first day of the Performance Period with respect to which the Deferral Election is made. For example, Regular Deferral Elections with respect to a new Plan Year must be made and become irrevocable no later than December 31 ^st of the preceding Plan Year.

(b)

Elements of Deferral Elections . A Participant shall set forth in a Deferral Election elections as to:

(i)

the percentage to be deferred of the Salary, Commissions or Bonus to be earned by the Participant in the Performance Period and to be contributed to the Plan as Deferral Contributions; and

(ii)

the form of payment for the distribution of such Deferral Contributions in the event of Retirement.

In addition, a Participant may select an Interim Distribution Date and, in that event, shall specify the date of such Interim Distribution and the portion of the Deferral Contributions to be distributed on such date.

(c)

How made . A Deferral Election shall be made by timely completing and returning a Deferral Agreement to the Committee. Failure to complete and file other Enrollment Forms shall not render the timely filing of a Deferral Agreement ineffective.

(d)

Types of Deferral Elections, When Made and When Effective . The Plan recognizes Mid-Year Deferral Elections, Regular Deferral Elections and Special Bonus Deferral Elections. Deferral Elections shall be made and shall become irrevocable within the time periods designated by the Committee, which shall be no later than the dates specified below:

(i)

Mid-Year Deferral Elections . A Mid-Year Deferral Election must be made within 30 days of the date on which an employee becomes eligible to participate and shall become irrevocable no later than the end of such 30 ^th day. The employee shall commence participation in the Plan and the Deferral Election shall become effective on the first day of the month next following the date on which the Deferral Election is made. Examples:

(A)

An employee becomes eligible to participate on June 16, 2008, and makes a Deferral Election on June 20, 2008. The employee’s Deferral Election is effective and the employee becomes an active Participant on July 1, 2008.

(B)

Same facts, except that the employee makes a Deferral Election on July 1, 2008. The employee’s Deferral Election is effective and the employee becomes an active Participant on August 1, 2008.

(C)

Same facts, except that the employee fails to make a Deferral Election prior to July 17, 2008. The employee may not make a Deferral Election with respect to the 2008 Plan Year, and any attempt by the employee to make such an election is ineffective and invalid.

(ii)

Regular Deferral Elections . A Regular Deferral Election shall be made within the time established by the Committee but, in any event, must be made prior to the first day of the next Plan Year. A Regular Deferral Election shall be effective as of the first day of the next Plan Year. Examples:

(A)

A Participant makes a Deferral Election within the time period established by the Committee (which, in all events, shall end before the first day of the next Plan Year). The Participant’s Deferral Election is effective on the first day of the next Plan Year.

(B)

The Committee requires Deferral Elections to be made by December 31 ^st with respect to the next Plan Year. A Participant seeks to make a Deferral Election on January 1 ^st of the next Plan Year. The Deferral Election is invalid and ineffective, and the Participant may not participate in the Plan for that Plan Year.

(iii)

Special Bonus Deferral Elections . Notwithstanding anything in this Plan to the contrary, the Committee shall have the discretion to authorize Special Bonus Deferral Elections. For such purpose, the Committee shall establish a Special Election Period for Bonus which shall end not later than the last day of the sixth month after the start of the Plan Year to which the Special Election Period relates, provided that Bonus is not ascertainable at any time during the Special Election Period and provided, further, that Participants making such Special Bonus Deferral Elections have performed services continuously from the later of the beginning of the performance period or the date the performance criteria are established through the date that the Special Bonus Deferral Elections are made. An employee who makes a Mid-Year Deferral Election may not make a Special Bonus Deferral Election.

(e)

Types of Compensation to which Deferral Elections are Applicable and How Applied . A Participant may elect to defer a percentage of one or more of Salary, Commissions and Bonus.

(i)

Salary Deferral Elections

(A)

Regular Salary Deferral Election . A Regular Salary Deferral Election that is timely made shall apply on a payroll basis to all Salary paid for services performed in the Plan Year.

(B)

Mid-Year Salary Deferral Election . A Mid-Year Salary Deferral Election that is timely made shall apply on a payroll basis to all Salary paid with respect to services performed on and after the effective date of the Mid-Year Salary Deferral Election through the end of the Plan Year.

(ii)

Commissions Deferral Elections

(E)

Regular Deferral Election . A Regular Commissions Deferral Election that is timely made shall apply on a payroll basis to all Commissions paid in the Plan Year.

(F)

Mid-Year Deferral Election . A Mid-Year Commissions Deferral Election that is timely made shall apply on a payroll basis to all Commissions paid on and after the effective date of the Mid-Year Commissions Deferral Election date though the end of the Plan Year.

(iii)

Bonus Deferral Elections

(A)

Regular Bonus Deferral Election . A Regular Bonus Deferral Election that is timely made shall apply to Bonus awarded for services performed in the Plan Year, though such Bonus is not payable until after the Performance Period ends.

(B)

Mid-Year Bonus Deferral Election . A Mid-Year Bonus Deferral Election shall apply to the portion of the Bonus allocable to services performed on and after the effective date of the Mid-Year Bonus Deferral Election. Such portion of a Participant’s Bonus shall be equal to a fraction, the numerator of which is the days in the Performance Period on and after the effective date of the Mid-Year Bonus Deferral Election and the denominator of which is the total number of days of the Plan Year, as applicable to the Participant. Examples:

(I)

An employee is hired on June 16, 2008, and begins to perform services and becomes eligible to participate in the Plan on that date. The employee makes a Mid-Year Bonus Deferral Election prior to July 1, 2008. The Mid-Year Bonus Deferral Election is effective as of July 1, 2008 with respect to that portion of the 2008 Bonus allocable to

services performed on and after July 1, 2008. Such portion is determined by multiplying the total Bonus payable to the Participant for 2008 by a fraction, the numerator of which is the number of days remaining in the 2008 Performance Period as of July 1, 2008 (184) and the denominator of which is the number of days in the 2008 Plan Year, as applicable to the Participant ( i.e. , on and after June 16, 2008, or 199).

(II)

Same facts except the individual makes a Mid-Year Bonus Deferral Election on or after July 1, 2008, but within 30 days of June 16, 2008. The Mid-Year Bonus Deferral Election is effective with respect to that portion of the 2008 Bonus allocable to services performed on and after August 1, 2008.

(III)

An employee performs services from January 1, 2008 onwards and becomes eligible to participate in the Plan on June 16, 2008. The employee makes a Mid-Year Bonus Deferral Election prior to July 1, 2008. The employee’s Mid-Year Bonus Deferral Election is effective as of July 1, 2008 with respect to that portion of the 2008 Bonus allocable to services performed on and after July 1, 2008. Such portion is determined by multiplying the total Bonus payable to the Participant for 2008 by a fraction, the numerator of which is the number of days remaining in the 2008 Performance Period as of July 1, 2008 (184) and the denominator of which is the number of days in the 2008 Plan Year, as applicable to the Participant (366).

(C)

Special Bonus Deferral Election . A Special Bonus Deferral Election shall be effective as of the first day of a Participant’s participation in the Plan with respect to the Plan Year and shall apply to the portion of the Bonus awarded for services performed on and after such date. Example: A Participant performs services continuously from the first day of the Plan Year and makes a timely Special Bonus Deferral Election in June, 2008. All of the Participant’s 2008 Bonus is subject to the Special Bonus Deferral Election.

ARTICLE 4. CONTRIBUTIONS, INVESTMENT ADJUSTMENTS AND TAXES

4.1 Deferral Contributions .

(a)

General . Pursuant to timely and otherwise valid Deferral Elections, a Participant may elect to defer amounts of Salary, Commissions or Bonus that would otherwise be payable to the Participant. Such Deferral Contributions shall be credited to a Deferral Contribution Account established in the name of the Participant.

(b)

Determination of Deferral Contributions . The amount of Deferral Contributions shall be determined on the basis of the percentages of Salary, Commissions or Bonus elected to be deferred by a Participant. Such amounts shall be deemed deferred to the Plan after all Elective Deferrals and shall be withheld from each payment of Salary, Commissions and Bonus.

(c)

Minimum and Maximum Deferrals . A Participant may elect to defer Salary, Commissions and Bonus in whole numbers, in the following minimum and maximum percentages:


Compensation Type	Minimum Percentage		Maximum Percentage
Salary	1	%	100	%
Commissions	1	%	100	%
Bonus	1	%	100	%

4.2 Selection of Hypothetical Investments . The Committee shall make a range of Hypothetical Investment options available for purposes of the Plan and may revise such options, from-to-time, in its sole discretion. A Participant’s Deferral Contributions with respect to a Plan Year shall be deemed invested in accordance with the Hypothetical Investments selected by the Participant pursuant to the Participant’s currently effective Investment Allocation and/or Reallocation Election. All Hypothetical Investment selections must be denominated in whole percentages unless otherwise permitted by the Committee. A Participant may make changes in selected Hypothetical Investments from time-to-time on such basis and by means of such procedures as may be authorized by the Committee.

4.3 Adjustment of Participant Accounts . A Participant’s Deferral Contribution Account shall be adjusted in accordance with the Hypothetical Investment(s) chosen by the Participant, subject to the conditions and procedures set forth herein or established by the Committee, from time to time. The overriding intent of such adjustments is that they shall reflect rates of return on predetermined actual investments within the meaning of Section 31.3121(v)(2)-1(d)(2)(B) of the Treasury Regulations. Any earnings generated under a Hypothetical Investment shall, at the Committee’s sole discretion, either be deemed to be reinvested in that Hypothetical Investment or reinvested in one or more other Hypothetical Investments designated by the Committee, provided that such designation by the Committee

must be made within a reasonable period of time after the date on which the earnings under a Hypothetical Investment are declared and provided, further, that earnings on investments made in accordance with such designations may be taken into account only on and after the date of such designations. A Participant’s Hypothetical Investments shall bear the reasonable and customary investment expenses and charges that are borne by investments of a like character. All notional acquisitions and dispositions of Hypothetical Investments which occur within a Participant’s Deferral Contribution Account, pursuant to the terms of the Plan, shall be deemed to occur at such times as the Committee shall determine to be administratively feasible in its sole discretion, and the Participant’s Deferral Contribution Account shall be adjusted accordingly, provided that such adjustment shall occur no less frequently than once per year. If a distribution or re-allocation must occur pursuant to the terms of the Plan and all or some portion of the Account Balance must be valued in connection with such distribution or re-allocation (to reflect Investment Adjustments), the Committee may in its sole discretion, unless otherwise provided for in the Plan, select a date or dates as closely proximate to such event as feasible for valuation purposes. Notwithstanding anything in this Plan to the contrary, any Investment Adjustments made to any Participants’ Deferral Contribution Accounts following a Change in Control shall be made in a manner no less favorable to Participants than the practices and procedures employed under the Plan, or as otherwise in effect, as of the date of the Change in Control.

4.4 Taxes .

(a)

Annual Withholding from Compensation . For any Plan Year in which Deferral Contributions are made to the Plan, the Employer shall withhold the Participant’s share of FICA and other employment taxes from the portion of the Participant’s compensation that is not deferred.

(b)

Payment of Taxes from Deferral Contribution Account . Notwithstanding Section 4.4(a), the Bank (or the trustee of the Trust, as applicable) shall cause a Participant’s Deferral Contribution Account to be decreased by the amount of any taxes imposed under Sections 3101, 3121(a), and Section 3121(v)(2) of the Code (collectively, “employment taxes”) on compensation deferred under this Plan, to the extent that such taxes have not been paid or are not available from the portion of the Participant’s compensation that is not deferred. Additionally, payment may be made from a Participant’s Deferral Contribution Account for the income tax withholding imposed under Section 3401 of the Code and any corresponding provisions of applicable State tax law on the payment of such employment taxes, as well as to pay the additional employment taxes and income tax withholdings attributable to the pyramiding wages and taxes. However, the total payment under this Section 4.4(b) may not exceed the aggregate employment taxes and income tax withholdings.

(c)

Withholding from Benefit Distributions . The Bank (or the trustee of the Trust, as applicable) shall withhold from any payments made to a Participant under this Plan all federal, state and local income, employment and other taxes required to be withheld by the Employer (or the trustee of the Trust, as applicable) in

connection with such payments, in amounts and in a manner to be determined in the sole discretion of the Employer (or the trustee of the Trust, as applicable).

(d)

Payment upon Income Inclusion under Section 409A . The Bank (or the trustee of the Trust, as applicable) shall cause a Participant’s Deferral Contribution Account to be decreased by the amount required to be included in income as a result of the failure of the Plan to comply with the requirements of Section 409A and the regulations thereunder.

4.5 Vesting . The Participant shall at all times be one hundred percent (100%) vested in all Deferral Contributions.

ARTICLE 5. CANCELLATION OF DEFERRAL ELECTIONS

5.1 General . Except as specifically provided in this Article 5, Deferral Elections may not be cancelled and are irrevocable.

5.2 Unforeseeable Emergencies and Hardship Distributions . If a Participant receives a distribution from this Plan due to an Unforeseeable Emergency or a Hardship Distribution pursuant to Section 1.401(k)-1(d)(3) of the Treasury Regulations from any plan maintained by the Employer or any Affiliate, the Participant’s Deferral Election(s) with respect to the current Performance Period shall be cancelled as soon as administratively feasible following such events.

5.3 Disability . If a Participant incurs a Disability, the Participant’s Deferral Election(s) with respect to the current Performance Period shall be cancelled, provided that the cancellation occurs no later than the later of the end of the Plan Year or the 15 ^th day of the third month following the date the Participant incurs the Disability. For purposes of this Section 5.3, “Disability” refers to any medically determinable physical or mental impairment resulting in the Participant’s inability to perform the duties of his or her position or any substantially similar position, where such impairment can be expected to result in death or can be expected to last for a continuous period of not less than six months.

ARTICLE 6. DISTRIBUTIONS

6.1 Interim Distributions . At the time, and as part of a Deferral Election, a Participant may elect to have a percentage of the Deferral Contributions deferred under the Deferral Election paid at an Interim Distribution Date designated by the Participant instead of at the Participant’s Benefit Distribution Date.

(a)

Time and Form of Payment . The amount of an Interim Distribution shall be measured as of the Interim Distribution Date (or, if information from securities markets is required to measure the Interim Distribution and such markets are closed on the Interim Distribution Date, as of the earliest date thereafter as practicable) and shall be paid in a lump sum within thirty (30) days of such Interim Distribution Date or as soon thereafter as is administratively feasible but no later than December 31 ^st of the year in which the Interim Distribution Date occurs.

(b)

Earlier Occurrence of Benefit Distribution Date . Notwithstanding a Participant’s election to designate an Interim Distribution Date, the portion of a Participant’s Deferral Contribution Account which would otherwise be subject to such Interim Distribution Date shall be distributable upon the Participant’s Benefit Distribution Date, if such date occurs prior to the Interim Distribution Date.

6.2 Distributions due to Unforeseeable Emergencies .

(a)

General . A Participant may make a request in writing to the Committee for a distribution of that portion of the Participant’s Deferral Contribution Account necessary to satisfy an Unforeseeable Emergency. Whether a Participant is faced with an Unforeseeable Emergency permitting a distribution under this Plan is to be determined based on the relevant facts and circumstances. A distribution on account of an Unforeseeable Emergency, however, may not be made to the extent that such emergency is or may be relieved through reimbursement or compensation from insurance or otherwise, by liquidation of the Participant’s assets, to the extent the liquidation of such assets would not cause severe financial hardship, or by cessation of deferrals under the Plan. The Committee shall determine, in its sole discretion, whether an Unforeseeable Emergency has occurred and the amount that is reasonably necessary to satisfy the Unforeseeable Emergency. If a request for distribution due to an Unforeseeable Emergency is approved by the Committee, the distribution shall be made as soon as administratively feasible following the date of such approval.

(b)

Amount of Distribution . Distributions on account of an Unforeseeable Emergency may not exceed the amount reasonably necessary to satisfy the emergency need (which may include amounts necessary to pay any Federal, State, local, or foreign income taxes or penalties reasonably anticipated to result from the distribution). Determinations of amounts reasonably necessary to satisfy the emergency need must take into account the additional compensation available to a

Participant pursuant to the cancellation of any currently effective Deferral Elections pursuant to Section 5.2 of this Plan. The determination of amounts reasonably necessary to satisfy the emergency need is not required to take into account any additional compensation that due to the Unforeseeable Emergency is available under another nonqualified deferred compensation plan.

(c)

Time and Form of Payment . A distribution on account of an Unforeseeable Emergency shall be made within thirty (30) days after the Committee’s determination that the Participant has experienced an Unforeseeable Emergency or as soon thereafter as is administratively feasible, provided that in no event may the distribution occur more than ninety (90) days after such date or may the Participant be given an election as to the taxable year in which the distribution is made.

6.3 Benefit Distribution Date . The distribution of the portion of a Participant’s Deferral Contribution Account not previously distributed on an Interim Distribution Date or on account of an Unforeseeable Emergency shall be made (or commence upon) the Participant’s Benefit Distribution Date, which shall be the earliest to occur of the date of a Participant’s Termination of Employment, Retirement, death, or Disability.

6.4 Distributions on Termination of Employment . If the Participant’s Benefit Distribution Date is the date of his or her Termination of Employment, the Participant shall receive a Termination Benefit.

(a)

Time and Form of Payment . The Termination Benefit shall be a lump sum payment equal to the Participant’s Account Balance, which, subject to Section 6.9(a), shall be paid within thirty (30) days after the Participant’s Benefit Distribution Date or as soon thereafter as is administratively feasible but no later than December 31 ^st of the year in which the Termination of Employment occurs.

(b)

Death Prior to Payment of Termination Benefit . If a Participant dies after his or her Termination of Employment but before the Termination Benefit is paid, the Participant’s unpaid Termination Benefit shall be paid to the Participant’s Beneficiary in a lump sum, subject to the timing rules stated in Section 6.4(a), above.

6.5 Distributions on Retirement . If the Participant’s Benefit Distribution Date is the date of his or her Retirement, the Participant shall receive a Retirement Benefit.

(a)

Time and Form of Payment of Retirement Benefit . At the time of, and as part of a Participant’s Deferral Election with respect to a Plan Year, the Participant shall make an election as to the form in which Deferral Contributions made under such election shall be distributed in the event that the Participant’s Benefit Distribution Date is the date of his or her Retirement. The Participant may elect to receive the Retirement Benefit in a lump sum or in substantially equal annual payments over a period not to exceed fifteen (15) years. The Retirement Benefit shall be payable

in the form elected by the Participant under the Participant’s applicable Deferral Election and, subject to Section 6.9(a), shall commence (or be fully paid, in the event a lump sum form of distribution was elected) within thirty (30) days after the Participant’s Benefit Distribution Date or as soon thereafter as is administratively feasible but no later than December 31 ^st of the year in which the Retirement occurs. In the case of installment payments, the initial installment shall be based on the value of the Participant’s Account Balance, measured as of his or her Benefit Distribution Date, and shall be equal to 1/n, where “n” is equal to the total number of annual benefit payments not yet distributed. Subsequent installment payments shall be computed in a consistent fashion, with the measurement date being the anniversary of the original measurement date, and shall be made in accordance with the same timing rules.

(b)

Death Prior to Completion of Retirement Benefit . If a Participant dies after Retirement but before the Retirement Benefit has been completed, the Participant’s unpaid Retirement Benefit payments shall be paid to the Participant’s Beneficiary in the same manner as they would have been paid to the Participant.

6.6 Distributions on Death; Time and Form of Payment . If the Participant’s Benefit Distribution Date is the date of his or death, the Participant’s Beneficiary shall be paid a Death Benefit. The Death Benefit shall be a lump sum payment equal to the Participant’s Account Balance and shall be paid to the Participant’s Beneficiary within thirty (30) days after the Participant’s Death or as soon thereafter as is administratively feasible but no later than December 31 ^st of the year in which the Participant’s death occurs.

6.7 Distributions on Disability . If a Participant determined by the Committee to have a Disability within the meaning of the Plan, the Participant’s Benefit Distribution Date shall be the date of such determination, and the Participant shall receive a Disability Benefit equal to his or her Account Balance.

(a)

Time and Form of Payment . The Disability Benefit shall be paid in a lump sum within thirty (30) days of the Participant’s Benefit Distribution or as soon thereafter as is administratively feasible but no later than December 31 ^st of the year in which the Disability occurs.

(b)

Eligibility for Retirement . Notwithstanding the foregoing, if the Participant is eligible to retire on the date on which he or she is determined to have a Disability, then the Participant shall be paid a Retirement Benefit in accordance with Section 6.5. For such purpose, the date on which the Participant is determined by the Committee to have a Disability shall be deemed to be the date of the Participant’s Retirement.

6.8 Payment by March 15 ^th Deemed Timely . Where a payment under this Article 6 is required to be made by December 31 ^st of the year in which the event giving rise to the payment occurs, the payment will be deemed timely if made by March 15 ^th of the following year,

provided that the employee is not permitted, directly or indirectly, to designate the taxable year of the payment.

6.9 Distributions to Specified Employees on Retirement or Termination of Employment .

(a)

Distributions to a Specified Employee on account of a Separation from Service that is Retirement or Termination of Employment may not be made (or commence, as applicable) earlier than the date which is six months after the Specified Employee’s Benefit Distribution Date (or, if earlier, the date of death of the employee). Example : A Specified Employee retires on January 1, 2009. Distributions on account of the Specified Employee’s Retirement may not be made prior to July 1, 2009. If the Specified Employee dies on March 1, 2009, distribution may be made on or after March 1, 2009.

(b)

The rule stated in 6.9(a) shall apply only to distributions to a Specified Employee that would otherwise have been made within the first six months after such employee’s Retirement or Termination of Employment and shall not operate to delay payments after such six month period. For example, annual payments scheduled to be made on the anniversary of the Specified Employee’s Retirement date pursuant to Section 6.5(a) shall continue to be made on such anniversary, and only the initial payment shall be delayed by six months pursuant to Section 6.9(a).

ARTICLE 7. BENEFICIARY DESIGNATION

7.1 Beneficiary . Each Participant shall have the right, at any time, to designate a Beneficiary or Beneficiaries to receive, in the event of the Participant’s death, those benefits payable under the Plan. The Beneficiary or Beneficiaries designated under this Plan may be the same as or different from the Beneficiary designation made under any other plan of the Employer.

7.2 Beneficiary Designation; Change . A Participant shall designate his or her Beneficiary by completing and signing a Beneficiary Designation Form, and returning it to the Committee or its designated agent. A Participant shall have the right to change his or her Beneficiary by completing, signing and submitting to the Committee a revised Beneficiary Designation Form in accordance with the Committee’s rules and procedures, as in effect from time to time. The submission of a new Beneficiary Designation Form shall constitute a revocation of all previously submitted Beneficiary Designation Forms. Facts as shown by the records of the Committee on the date of death shall be conclusive.

7.3 Acknowledgment . No designation or change in designation of a Beneficiary shall be effective until received, accepted and acknowledged in writing by the Committee or its designated agent.

7.4 No Beneficiary Designation . If a Participant fails to designate a Beneficiary as provided above or if all designated Beneficiaries on the currently effective Beneficiary Designation Form predecease the Participant or die prior to complete distribution of the Participant’s benefits, then the Participant’s designated Beneficiary shall be deemed to be the Participant’s surviving spouse. If the Participant has no surviving spouse, the benefits remaining under the Plan shall be payable to the executor or personal representative of the Participant’s estate.

7.5 Discharge of Obligations . The payment of benefits under the Plan to a Beneficiary shall fully and completely discharge the Bank and the Committee from all further obligations under this Plan with respect to the Participant, and the Participant’s Participation Agreement shall terminate upon such full payment of benefits.

ARTICLE 8. TERMINATION, AMENDMENT OR MODIFICATION

8.1 Termination . Although the Bank anticipates that it will continue the Plan for an indefinite period of time, there is no guarantee that it will continue the Plan or will not terminate the Plan at some time in the future. Accordingly, the Bank reserves the right to terminate the Plan, in its sole discretion, at any time, with or without notice, by action of its Board of Directors; provided, however, that such termination shall not affect the Employer’s payment obligations with respect to Deferral Contributions then existing, and the Employer shall not accelerate payment of such Deferral Contributions (or cause the trustee of the Trust to accelerate payment of such obligations) but, instead, shall make payment in due course, except under any of the following conditions:

(a)

The Bank terminates and liquidates the Plan within 12 months of a corporate dissolution taxed under Section 331 of the Code (pertaining to corporate liquidations) or with the approval of a Bankruptcy Court pursuant to Section 503(b)(1)(A) of the Bankruptcy Code, provided that the amounts deferred under the Plan are included in the Participants’ gross incomes in the latest of the following years (or, if earlier, the taxable year in which the amount is actually or constructively received):

(1)

The calendar year in which the termination and liquidation of the Plan occurs.

(2)

The first calendar year in which the amount is no longer subject to a substantial risk of forfeiture.

(3)

The first calendar year in which the payment is administratively practicable.

(b)

The Bank terminates and liquidates the Plan pursuant to an irrevocable action taken by the Bank within the 30 days preceding or the 12 months following a Change in Control, provided that all nonqualified deferred compensation plans of the Bank or any Affiliate that are required to be aggregated with this Plan under Section 1.409A-1(c)(2) of the Treasury Regulations with respect to Participants in the Plan are also terminated and liquidated with respect to each Participant that experienced the Change in Control event so that, under the terms of the termination and liquidation, all such Participants are required to receive all amounts of deferred compensation under this Plan and all such other plans within 12 months of the date all actions necessary to terminate and liquidate this Plan and all such other plans are taken by the Bank and its Affiliates.

(c)

The Bank terminates and liquidates the Plan, provided that:

(1)

The termination and liquidation does not occur proximate to a downturn in the financial health of the Bank or an Affiliate;

(2)

The Bank and its Affiliates terminate and liquidate all nonqualified deferred compensation plans that are subject to aggregation with this Plan under Section 1.409A-1(c) of the Treasury Regulations;

(3)

No payments in liquidation of the Plan are made within 12 months of the date that the Bank takes all necessary action to irrevocably terminate and liquidate the Plan, other than payments that would be payable under the terms of the Plan if the action to terminate and liquidate the Plan had not occurred;

(4)

All payments are made within 24 months of the date the Bank takes all necessary action to irrevocably terminate and liquidate the plan; and

(5)

Neither the Bank nor any Affiliate adopts a new plan that would be aggregated with any terminated and liquidated plan under Section 1.409A-1(c) if the same employee participated in both plans, at any time within three years following the date the Bank takes all necessary action to irrevocably terminate and liquidate the Plan.

(d)

Such other events and conditions as the Commissioner of the Internal Revenue Service may prescribe in generally applicable guidance published in the Internal Revenue Bulletin.

8.2 Amendment . The Bank may amend the Plan at any time by action of its Board of Directors in whatever respects it may deem necessary, appropriate or desirable, with or without notice, subject to the following limitations:

(a)

No amendment or modification shall be effective to decrease or restrict the value of a Participant’s Account Balance in existence at the time the amendment or modification is made, calculated as if the Participant had experienced a Termination of Employment as of the effective date of the amendment or modification, or, if the amendment or modification occurs after the date upon which the Participant was eligible to Retire, calculated as if the Participant had Retired as of the effective date of the amendment or modification.

(b)

Except as specifically provided in Section 8.1, no amendment or modification shall be made after a Change in Control which adversely affects the vesting, calculation or payment of benefits hereunder or diminishes any other rights or protections any Participant or Beneficiary would have had, but for such amendment or modification, unless each affected Participant or Beneficiary consents in writing to such amendment.

(c)

No amendment shall have the effect of accelerating the distribution of Deferral Contributions accrued prior to such amendment, including through the addition or deletion of a payment option.

(d)

Any amendment of the Plan which has the effect of further delaying or changing the form of payments to any Participant on Termination of Employment shall be subject to the subsequent deferral rules of Section 1.409A-2(b) of the Treasury Regulations. Such amendment shall not take effect until at least 12 months after the date of the amendment, and payments with respect to such amendment shall be deferred for a period of not less than five years from the date such payment would otherwise have been made or have commenced.

(e)

In no event shall an amendment to the Plan materially enhance benefits or rights existing as of October 3, 2004 under the 2004 Plan, or add a new material benefit or right affecting amounts earned and vested before January 1, 2005, except as may be permitted under Section 1.409A-6(a)(4) of the Treasury Regulations or its successor.

The Compensation Committee of the Board of Directors of Hawaiian Electric Industries, Inc., may make recommendations to the Bank on amendments to the Plan from time-to-time, and the Bank shall give due consideration to such recommendations.

8.3 Effect of Payment . The full payment of the applicable benefit under the provisions of the Plan shall completely discharge all obligations under this Plan to a Participant and the Participant’s designated Beneficiaries, and the Participation Agreement of such a Participant shall terminate.

ARTICLE 9. ADMINISTRATION

9.1 Committee . This Plan shall be administered by the Committee. Members of the Committee may be Participants under this Plan. The Committee shall have all rights, powers, discretions, and authority necessary or desirable to administering the Plan, including, without limitation, the discretion and authority to make, interpret, and enforce all appropriate rules and regulations for the administration of this Plan, to rule on claims and decide all questions regarding eligibility and benefits, and to decide or resolve any and all questions or ambiguities that may arise in connection with the interpretation of the Plan. Any individual serving on the Committee who is a Participant shall not vote or act on any matter relating solely to himself or herself. When making a determination or calculation, the Committee shall be entitled to rely on information furnished by a Participant or the Bank.

9.2 Agents . In the administration of this Plan, the Committee may, from time to time, employ agents and delegate to them such administrative duties as it sees fit (including acting through a duly appointed representative) and may from time to time consult with counsel who may be counsel to any Employer.

9.3 Binding Effect of Decisions . The decision or action of the Committee with respect to any question arising out of or in connection with the administration, interpretation and application of the Plan and rules and regulations promulgated hereunder shall be final and conclusive and binding upon all persons having any interest in the Plan.

9.4 Indemnity of Committee . The Bank shall indemnify and hold harmless the members of the Committee, and any employee to whom duties of the Committee may be delegated, against any and all claims, losses, damages, expenses or liabilities arising from any action or failure to act with respect to this Plan, except in case of willful misconduct by the Committee or any of its members or any such employee.

9.5 Employer Information . To enable the Committee to perform its functions, the Employer shall supply full and timely information to the Committee on all matters relating to the compensation of its Participants, the date and circumstances of the Retirement, Disability, death or Termination of Employment of its Participants, and such other pertinent information as the Committee may reasonably require.

ARTICLE 10. CLAIMS PROCEDURES

10.1 Presentation of Claim . Any Participant and any Beneficiary, Personal Representative or Executor of a deceased Participant (such Participant or Beneficiary being referred to below as a “Claimant”) may deliver to the Committee a written claim for a determination with respect to the amounts distributable to such Claimant from the Plan. If such a claim relates to the contents of a notice received by the Claimant, the claim must be made within sixty (60) days after such notice was received by the Claimant. All other claims must be made within one hundred eighty (180) days of the date on which the event that caused the claim to arise occurred. The claim must state with particularity the determination desired by the Claimant.

10.2 Decision on Claim . Within ninety (90) days after receipt of a claim, the Committee shall send to the Claimant written notice of the granting or denying, in whole or in part, of such claim, unless special circumstances require an extension of time for processing the claim. In no event may an extension exceed ninety (90) days from the end of the initial period. If such extension is necessary, the Claimant shall be given written notice to this effect prior to the expiration of the initial ninety (90) day period which shall specify the special circumstances requiring extension. If notice of the denial of a claim is not furnished in accordance with this Section, then the claim shall be deemed denied, and the Claimant shall be permitted to exercise the Claimant’s right to seek review pursuant to Sections 10.4 and 10.5.

10.3 Notification of Decision . The Committee shall consider a Claimant’s claim within a reasonable time, and shall notify the Claimant in writing:

(a)

that the Claimant’s requested determination has been made, and that the claim has been allowed in full; or

(b)

that the Committee has reached a conclusion contrary, in whole or in part, to the Claimant’s requested determination, and such notice must set forth in a manner calculated to be understood by the Claimant:

(i)

the specific reason(s) for the denial of the claim, or any part of it;

(ii)

specific reference(s) to pertinent provisions of the Plan upon which such denial is based;

(iii)

a description of any additional material or information necessary for the Claimant to perfect the claim and an explanation of why such material or information is necessary; and

(iv)

an explanation of the claim review procedure set forth in Section 10.4 below.

10.4 Review of a Denied Claim . Within sixty (60) days after receiving a notice from the Committee that a claim has been denied, in whole or in part, a Claimant (or the Claimant’s

duly authorized representative) may file with the Committee a written request for a review of the denial of the claim. Thereafter, but not later than thirty (30) days after the review procedure began, the Claimant (or the Claimant’s duly authorized representative):

(a)

may review pertinent documents;

(b)

may submit written comments or other documents; and/or

(c)

may request a hearing, which the Committee, in its sole discretion, may grant.

10.5 Decision on Review . The Committee shall render its decision on review not later than sixty (60) days after the filing of a written request for review of the denial, unless a hearing is held or other special circumstances require additional time, in which case the Committee’s decision must be rendered within one hundred twenty (120) days after such date. If such extension is necessary, the claimant shall be given written notice of the extension prior to the expiration of the initial sixty (60) day period. If notice of the decision on the review is not furnished in accordance with this Section, then the claim shall be deemed denied. Such decision must be written in a manner calculated to be understood by the Claimant, and it must contain:

(a)

the specific reasons for the decision;

(b)

specific reference(s) to pertinent Plan provisions upon which the decision was based; and

(c)

such other matters as the Committee deems relevant.

10.6 Preservation of Other Remedies . After exhaustion of the claims procedures provided under this Plan, nothing shall prevent any person from pursuing any other legal or equitable remedy otherwise available, provided that no action shall be commenced or maintained more than ninety (90) days after the final decision of the Plan Administrator on review.

10.7 Administrative Exhaustion . Each and every claim arising under this Plan shall be subject to the claims review procedures set forth in this Article 10. No person claiming the benefit of this Plan may seek judicial or other resolution of any claim, issue or controversy without first exhausting administrative remedies.

ARTICLE 11. TRUST

11.1 Establishment of the Trust . The Bank may establish one or more Trusts to which it may transfer such assets as it determines in its sole discretion to assist in meeting its obligations under the Plan.

11.2 Relationship of the Plan and the Trust . The provisions of the Plan and Enrollment Forms shall govern the rights of a Participant to make deferrals to and receive distributions from the Plan. The provisions of the Trust shall govern the rights of the Bank, Participants and the creditors of the Bank to the assets transferred to the Trust.

11.3 Distributions from the Trust . The Bank’s obligations under the Plan may be satisfied with Trust assets distributed pursuant to the terms of the Trust, and any such distribution shall reduce the Bank’s obligations under this Agreement.

11.4 No Offshore Trust . Any Trust established pursuant for purposes of this Plan must be located within the United States.

ARTICLE 12. MISCELLANEOUS

12.1 Status of the Plan . The Plan is intended to be a nonqualified deferred compensation plan within the meaning of Section 409A and other applicable Sections of the Code and that “is unfunded and is maintained by an employer primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees” within the meaning of Sections 201(2), 301(a)(3), and 401(a)(1) of ERISA. The Plan shall be administered and interpreted in a manner consistent with that intent. All Participant accounts and all credits and other adjustments to such Participant accounts shall be bookkeeping entries only and shall be utilized solely as a device for the measurement and determination of amounts to be paid under the Plan. No Participant accounts, credits or other adjustments under the Plan shall be interpreted as an indication that any benefits under the Plan are in any way funded.

12.2 Unsecured General Creditor . Participants and their Beneficiaries, heirs, successors and assigns shall have no legal or equitable rights, interests or claims in any property or assets of the Bank. For purposes of the payment of benefits under this Plan, any and all of the Bank’s assets, shall be, and remain, the general, unpledged, unrestricted assets of the Bank. The Bank’s obligation under the Plan shall be merely that of an unfunded and unsecured promise to pay benefits in the future.

12.3 Employer’s Liability . The Bank’s liability for the payment of benefits shall be defined only by the Plan and the Participation Agreement, as entered into between the Bank and a Participant. The Bank shall have no obligation to a Participant under the Plan except as expressly provided in the Plan and Participation Agreement.

12.4 Nonassignability . Neither a Participant nor any other person shall have any right to commute, sell, assign, transfer, pledge, anticipate, mortgage or otherwise encumber, transfer, hypothecate, alienate or convey in actual receipt, the amount, if any, payable hereunder, or any part thereof, which are, and all rights to which are expressly declared to be, non-assignable and non-transferable. No part of the amounts payable shall, prior to actual payment, be subject to seizure, attachment, garnishment or sequestration for the payment of any debts, judgments, alimony or separate maintenance owed by a Participant or any other person, be transferable by operation of law in the event of a Participant’s or any other person’s bankruptcy or insolvency or be transferable to a spouse as a result of a property settlement or otherwise.

12.5 Not a Contract of Employment . Under the terms and conditions of this Plan and the Participation Agreement, this Plan shall not be deemed to constitute a contract of employment between the Bank and the Participant. Nothing in this Plan or any Participation Agreement shall be deemed to give a Participant the right to be retained in the service of the Bank as an Employee or to interfere with the right of the Bank to discipline or discharge the Participant at any time.

12.6 Furnishing Information . A Participant or his or her Beneficiary will cooperate with the Committee by furnishing any and all information requested by the Committee and shall take such other actions as may be requested in order to facilitate the administration of the Plan

and the payments of benefits hereunder, including, but not limited to, taking such physical examinations as the Committee may deem necessary.

12.7 Terms . Except when otherwise indicated by the context, any masculine or feminine terminology used herein shall also include the neuter and other gender, and the use of any term in the singular or plural shall also include the opposite number

12.8 Captions . The captions of the articles, sections or paragraphs of this Plan are for convenience only and shall not control or affect the meaning of construction of any of its provisions.

12.9 Governing Law . The provisions of this Plan shall be construed and interpreted according to the laws of the State of Hawaii without regard to its conflicts of laws principles.

12.10 Notice . Any notice or filing required or permitted to be given to the Committee under this Plan shall be sufficient if in writing and hand-delivered, or sent by registered or certified mail, to the address below:


(via hand-delivery)		(via registered or certified mail)
General Counsel		American Savings Bank
American Savings Bank		P.O. Box 2300
915 Fort Street Mall, 11 ^th Floor		Honolulu, HI 96804
Honolulu, HI 96813		Attn: General Counsel

Such notice shall be deemed given as of the date of delivery or, if delivery is made by mail, as of the date shown on the postmark or the receipt for registration or certification.

Any notice or filing required or permitted to be given to a Participant under this Plan shall be sufficient if in writing and hand-delivered, or sent by mail, to the last known address of the Participant.

12.11 Successors . The provisions of this Plan shall bind and inure to the benefit of the Bank and its successors and the Participant and the Participant’s designated Beneficiaries.

12.12 Validity . In case any provision of this Plan shall be illegal or invalid for any reason, said illegality or invalidity shall not affect the remaining parts hereof, but this Plan shall be construed and enforced as if such illegal or invalid provision had never been inserted herein.

12.13 Incompetent . If the Committee determines in its sole discretion that a benefit under this Plan is to be paid to a minor, a person declared incompetent or to a person incapable of handling the disposition of that person’s property, the Committee may direct payment of such benefit to the guardian, legal representative or person having the care and custody of such minor, incompetent or incapable person. The Committee may require proof of minority, incompetence, incapacity or guardianship, as it may deem appropriate prior to distribution of the benefit. Any payment of a benefit shall be a payment for the account of the Participant and the Participant’s

Beneficiary, as the case may be, and shall be a complete discharge of any liability under the Plan for such payment amount.

12.14 Insurance . The Bank, on its own behalf or on behalf of the trustee of the Trust, and in its sole discretion, may apply for and procure insurance on the life of the Participant, in such amounts and in such forms as the Trust may choose. The Bank or the trustee of the Trust, as the case may be, shall be the sole owner and beneficiary of any such insurance. The Participant shall have no interest whatsoever in any such policy or policies, and at the request of the Bank shall submit to medical examinations and supply such information and execute such documents as may be required by the insurance company to whom the Bank has applied for insurance.

* * *

IN WITNESS WHEREOF, the Bank has signed this restated Plan document on October 24, 2008.


AMERICAN SAVINGS BANK, F.S.B.

By		/s/ Beth Whitehead
Its		Chief Administrative Officer

HEI Exhibit 10.8

AMERICAN SAVINGS BANK

SUPPLEMENTAL EXECUTIVE RETIREMENT, DISABILITY,

AND DEATH BENEFIT PLAN

Effective January 1, 2009

TABLE OF CONTENTS


		Page
ARTICLE I	DEFINITIONS	1

ARTICLE II	ELIGIBILITY	4

ARTICLE III	CONTRIBUTIONS	5

ARTICLE IV	BENEFITS	5

Section 4.1	Normal Retirement Benefit	5

Section 4.2	Early and Termination Retirement Benefits	6

Section 4.3	Vesting	8

Section 4.4	Time and Form of Payment of Normal and Subsidized Early Retirement Benefit	8

Section 4.5	Time and Form of Payment of Non-Subsidized Early Retirement Benefit	9

Section 4.6	Time and Form of Payment of Termination Retirement Benefit	10

Section 4.7	Transition Elections in 2008	11

Section 4.8	Death Benefits	11

Section 4.9	Disability Benefits	12

Section 4.10	Lump-Sum Cashouts of Certain Benefits	12

Section 4.11	Forfeiture in the Event of Termination for Cause	13

ARTICLE V	ADMINISTRATION	13

Section 5.1	The Committee	13

Section 5.2	Expenses	14

ARTICLE VI	INDEMNIFICATION	14

ARTICLE VII	CLAIMS PROCEDURES	14

Section 7.1	Claims Procedure	14

Section 7.2	Review Procedure	15

Section 7.3	Special Rules for Disability Claims	16

ARTICLE VIII	AMENDMENT, TERMINATION, AND MERGER	16

Section 8.1	Amendment	16

Section 8.2	Termination	16

Section 8.3	Merger, Etc. of the Bank	16

-i-

TABLE OF CONTENTS

(continued)


		Page
ARTICLE IX	MISCELLANEOUS	17

Section 9.1	No Right To Employment	17

Section 9.2	Inalienability	17

Section 9.3	Facility of Payment	17

Section 9.4	Tax Withholding	17

Section 9.5	Construction of Plan	17

Section 9.6	Forms	17

-ii-

AMERICAN SAVINGS BANK

SUPPLEMENTAL EXECUTIVE RETIREMENT, DISABILITY,

AND DEATH BENEFIT PLAN

PROLOGUE

American Savings Bank, F.S.B., (the “Bank”) sponsors the American Savings Bank Supplemental Executive Retirement, Disability, and Death Benefit Plan (the “Plan”) to assist the Bank in attracting and retaining senior management personnel who by reason of training, education, experience, and ability are capable of materially affecting the Bank’s profitability and performance. Except as otherwise provided herein, the Plan is amended and restated effective January 1, 2009. As restated, the Plan is intended to comply with the final regulations under Section 409A of the Internal Revenue Code of 1986, as amended, (the “Code”). From January 1, 2005 (the general effective date of Section 409A of the Code) through December 31, 2008, the Plan has been administered in accordance with the Plan’s terms and a reasonable, good-faith interpretation of Section 409A of the Code.

The Plan is unfunded and maintained for a select group of management employees. It is not intended to meet or be subject to the qualification requirements of Section 401(a) of the Code.

ARTICLE I

DEFINITIONS

The following terms as used herein shall have the indicated meaning unless a different meaning is plainly required by the context.

1.1 Actuarial Equivalent means an amount and form of benefit certified by an actuary to be mathematically equivalent in value to a given amount and form of benefit on the basis of the assumptions applicable under the Retirement Plan. Plan benefits that are deemed to be “actuarially reduced,” “actuarially increased,” or “actuarially adjusted” shall be computed as the Actuarial Equivalent of the benefit being replaced.

1.2 Associated Company means the Company and any corporation that is a member of the same controlled group of corporations (within the meaning of Section 1563(a) of the Code, determined without regard to Section 1563(a)(4) and (e)(3)(C) of the Code) as the Company. A corporation shall be regarded as an Associated Company only during the period it is a member of such controlled group of corporations.

1.3 Bank means American Savings Bank, F.S.B.

1.4 Bonus means the award(s) earned under the Hawaiian Electric Industries, Inc. Executive Incentive Compensation Plan or the American Savings Bank Performance Bonus Plan, as applicable, whether deferred or nondeferred, and whether paid in the form of cash or stock.

1.5 Code means the Internal Revenue Code of 1986, as amended.

1.6 Committee means the Compensation Committee of the Company’s Board of Directors.

1.7 Company means Hawaiian Electric Industries, Inc.

1.8 Compensation means the total salary, wages, and other monetary remuneration, if any, paid to a Participant by a Participating Employer and required to be set forth in Box 1 of the Participant’s Form W-2 for a particular Plan Year, modified to include : (a) all elective contributions to arrangements qualifying under Sections 125, 132(f)(4), or 401(k) of the Code and (b) effective May 1, 2000, elective deferrals to the Bank’s Select Deferred Compensation Plan; and further modified to exclude : (c) commissions, (d) employer contributions to any employee benefit plan (other than elective contributions), (e) stock options or other equity compensation, (f) amounts paid under the Hawaiian Electric Industries, Inc. Long-Term Incentive Plan, (g) 50% of the Bonus paid to the Participant during the Plan Year, (h) benefits paid out of the Bank’s Select Deferred Compensation Plan, and (i) amounts paid by a Participating Employer to or on behalf of the Participant for “fringe benefits,” such as (but not limited to) group life and health insurance, automobile allowance, club memberships and dues, and expense reimbursements.

Generally, Compensation does not include severance payments or other amounts paid after separation from service. However, Compensation shall include amounts paid by the later of 2 ¹ / 2 months after the Participant’s separation from service or the end of the calendar year that includes the date of the Participant’s separation from service, if the payment is regular compensation or a bonus that would be included in Compensation under the preceding paragraph for services during the Participant’s regular working hours, and, absent the separation from service, the payments would have been paid to the Participant while the Participant continued in employment with the Participating Employer.

Compensation shall not be limited by Section 401(a)(17) of the Code.

1.9 Disabled or Disability means the Participant (a) is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, or (b) is, by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, receiving income replacement benefits for a period of not less than 3 months under an accident and health plan covering employees of the Bank. In addition to the foregoing, a Participant shall be deemed Disabled as of the date the Social Security Administration determines the Participant to be totally disabled. Notwithstanding the foregoing, in no event shall any self-inflicted injury or intentionally induced sickness or any injury or sickness arising from the commission of any unlawful act or enterprise by the Participant constitute a Disability for purposes of this Plan.

1.10 ERISA means the Employee Retirement Income Security Act of 1974, as amended.

1.11 Final Average Compensation means the average annual Compensation of a Participant (converted to a monthly amount) during the five consecutive calendar Years of Service affording the highest such average during the Participant’s last ten calendar Years of Service, or during the total months of service if the Participant has less than five calendar Years of Service. Final Average Compensation is used to calculate the normal retirement benefit under Section 4.1 and the early retirement and termination retirement benefits under Section 4.2.

1.12 Final Pay means the sum of (1) a Participant’s monthly salary at the time of the Participant’s Disability or death plus (2) 50% of the average annual Bonus paid to such Participant in the thirty-six (36) months preceding the month in which the Participant became Disabled or died, such average annual Bonus to be divided by twelve (12) to yield a monthly amount. Final Pay is used to calculate the active Participant death benefit under Section 4.8(a) and the Disability benefit under Section 4.9.

1.13 Normal Retirement Date means the first day of the calendar month coinciding with or next following the Participant’s 65th birthday.

1.14 Participant means an officer of the Bank or one of the Bank’s subsidiaries whose participation in this Plan is approved by resolution of the Committee in accordance with Article II.

1.15 Participating Employer means the Bank and any subsidiary of the Bank to which participation in the Plan is extended.

1.16 Plan means the American Savings Bank Supplemental Executive Retirement, Disability, and Death Benefit Plan, as described in this instrument, including all amendments hereto.

1.17 Plan Year means the calendar year.

1.18 Postponed Retirement Date means, in the case of a Participant who continues in employment with a Participating Employer after the Participant’s Normal Retirement Date, the first day of the calendar month coinciding with or next following the Participant’s Separation from Service.

1.19 Primary Social Security Benefit means the monthly amount of primary old age insurance benefits available to a Participant at the Participant’s Normal Retirement Date or Postponed Retirement Date, as applicable, under the provisions of Title II of the Social Security Act as in effect for the year during which the Participant Separates from Service, without regard to any increases in the wage base or benefit levels or any other change in the law that takes effect thereafter and, if the Participant retires prior to reaching his or her Normal Retirement Date, assuming the Participant’s salary would have remained constant to his or her Normal Retirement Date.

1.20 Retirement Plan means the American Savings Bank Retirement Plan, as amended from time to time.

1.21 Separation from Service or Separates from Service is defined by reference to Treasury Regulation Section 1.409A-1(h) and generally means termination of employment from the Participating Employers and Associated Companies.

1.22 Spouse means a person married to a Participant as of the earlier of the date the Participant begins to receive benefits under this Plan or the date the Participant dies. A person who marries a Participant after the Participant’s benefit commencement date shall not be a Spouse for purposes of this Plan and shall have no Spousal rights to benefits hereunder.

1.23 Year of Participation means each 12-month period of employment beginning with the date the Participant commences participation in the Plan. If a non-vested Participant Separates from Service and is subsequently reemployed by a Participating Employer, the Committee may determine in its discretion whether to re-admit the former Participant as a Participant and, if so, whether to credit the Participant’s Years of Participation prior to the break in service in determining vesting credit under the Plan. If a vested Participant Separates from Service and is subsequently reemployed by a Participant Employer and readmitted as a Participant by the Committee, the Participant’s Years of Participation before and after the break in service shall be aggregated for vesting purposes. Notwithstanding anything in the Plan to the contrary, if a Participant is readmitted as a Participant following reemployment, the Participant shall not be permitted to make a new election as to the time and form of benefit, except to the extent allowed under the rules for subsequent elections in Treasury Regulation Section 1.409A-2(b).

1.24 Year of Service means each 12-month period beginning with the date the Participant commences employment with a Participating Employer and ending on the date the Participant Separates from Service with all the Participating Employers. Years of Service with an Associated Company other than a Participating Employer shall not count for benefit accrual purposes, but shall count for vesting purposes and early retirement eligibility. If a non-vested Participant Separates from Service and is subsequently reemployed by a Participating Employer, the Committee may determine in its discretion whether to readmit the former Participant as a Participant and, if so, whether to credit the Participant’s Years of Service prior to the break in service in determining vesting credit and benefit accrual under the Plan. If a vested Participant Separates from Service and is subsequently reemployed by a Participant Employer and readmitted as a Participant by the Committee, the Participant’s Years of Service before and after the break in service shall be aggregated for all purposes under the Plan.

ARTICLE II

ELIGIBILITY

An officer of the Bank or one of the Bank’s subsidiaries shall become a Participant only if the officer’s participation in the Plan has been approved by the Committee. A Participant shall commence participation in the Plan as of the latest of (i) the date designated by the Committee, (ii) the date the Committee approves the Participant’s participation in the Plan, or (iii) the date the Participant first performs an hour of service for the Bank. Until such time as a Participant commences participation in this Plan, the Participant shall have no rights under this Plan and no right to participate in the Plan in the future.

ARTICLE III

CONTRIBUTIONS

The Participating Employers shall pay the entire cost of the Plan from their general assets. No separate trust fund shall be established in connection with the Plan.

ARTICLE IV

BENEFITS

Section 4.1 Normal Retirement Benefit

If a Participant retires or Separates from Service with the Participating Employers and the Associated Companies on or after attaining age 65, the Participant shall be entitled to receive the normal retirement benefit described in this Section 4.1, payable in the form and at the time specified in Section 4.4.

(a) Amount of Benefit . The normal retirement benefit is the following monthly amount payable as a single life annuity for the life of the Participant and determined as though it commenced on the Participant’s Normal Retirement Date or Postponed Retirement Date, as applicable: 60% of the Participant’s Final Average Compensation multiplied by a fraction, the numerator of which is the number of the Participant’s Years of Service (but not more than 20) and the denominator of which is 20, reduced by the offsets described in Section 4.1(b).

(b) Offsets . The normal retirement benefit shall be offset or reduced by the following benefits received or receivable by the Participant:

(1) the vested accrued benefit payable to the Participant from the Retirement Plan (and from any other tax-qualified defined benefit pension plan sponsored by an Associated Company) as of the Participant’s Normal Retirement Date or Postponed Retirement Date, as applicable;

(2) The value of the Participant’s aggregate vested account balance in, or any prior payment from, the Hawaiian Electric Industries Retirement Savings Plan (the “HEIRS Plan”) and any other tax-qualified defined contribution retirement plan maintained or formerly maintained by a Participating Employer or an Associated Company (exclusive of any account balance or payment derived solely from employee contributions or the Participant’s elective contributions under Section 401(k) of the Code); and

(3) the Participant’s Primary Social Security Benefit.

(c) DC Plan Offset Assumptions and Definitions . The value of the benefits payable or paid from the HEIRS Plan and any other defined contribution plan shall be computed in the form of a single life annuity over the life expectancy of the Participant commencing on the Participant’s Normal Retirement Date or Postponed Retirement Date, as applicable, using the “applicable interest rate” and “applicable mortality table,” as defined in Section 417(e)(3) of the Code, in effect for the year in which the Participant’s Separation from Service occurs . A Participant’s “aggregate vested account balance” in the HEIRS Plan and any other defined contribution plan shall be determined as of the date of the Participant’s Separation from Service,

but taking into account any AmeriMatch or other matching contribution that is expected to be made with respect to 401(k) contributions from the Participant’s final paycheck and disregarding any AmeriShare or other discretionary employer contribution that might be made with respect to the Plan Year in which the Participant Separates from Service. Any “prior payment” from the HEIRS Plan or another defined contribution plan shall be equal to the amount of such payment without adjustment for interest from the date of payment.

(d) Minimum Benefit . Prior to this restatement, the Plan provided a minimum normal retirement benefit equal to the benefit the Participant would have received under the Hawaiian Electric Industries, Inc. Excess Pay Supplemental Executive Retirement Plan (the “Excess Pay SERP”) if the Participant were a participant in the Excess Pay SERP. This minimum benefit shall no longer apply after December 31, 2008; provided, however, that the normal retirement benefit of any Participant who was a Participant in the Plan on December 31, 2008, shall not be less than the benefit that would have been payable if the Participant had retired under the terms of the Excess Pay SERP on December 31, 2008.

Section 4.2 Early and Termination Retirement Benefits

If a Participant Separates from Service after meeting the vesting requirement set forth in Section 4.3, but prior to the date the Participant attains age 65, the Participant shall be entitled to receive either the subsidized early retirement benefit described in Section 4.2(a), the non-subsidized early retirement benefit described in Section 4.2(b), or the termination retirement benefit described in Section 4.2(c). See Sections 4.4 through 4.6 for the form and timing of early retirement and termination retirement benefits. This Section 4.2 is effective January 1, 2008.

(a) Subsidized Early Retirement Benefit . If the Participant has attained age 55 and completed 10 Years of Service when the Participant Separates from Service, the Participant shall be entitled to the normal retirement benefit determined under Section 4.1 as adjusted under this Section 4.2(a). Specifically, the following adjustments shall be made:

(1) In determining the normal retirement benefit, the offsets in Sections 4.1(b)(1) and (2) shall be disregarded.

(2) The normal retirement benefit as adjusted under subsection (1) above shall be reduced to reflect the fact that payments will commence as of an earlier date according to the following scale interpolated to the nearest full month:


Age at Time Payments Begin		Percentage of Normal Retirement Benefit Payable
55		40.20%
56		43.69%
57		47.54%
58		51.83%
59		56.59%
60		70.00%
61		80.00%
62		90.00%


63		95.00%
64		98.00%
65		100.00%

(3) The subsidized early retirement benefit determined after applying subsections (1) and (2) above shall then be reduced by the offsets in Sections 4.1(b)(1) and (2), provided, however, that the offset in Section 4.1(b)(1) shall be determined as the reduced benefit payable as of the Participant’s early retirement date using the early reduction factors then in effect under the Retirement Plan (or other applicable tax-qualified defined benefit pension plan) and the offset in Section 4.1(b)(2) shall be computed in the form of an immediately commencing annuity using the “applicable interest rate” and “applicable mortality table,” as defined in Section 417(e)(3) of the Code, in effect at that time .

(b) Non-Subsidized Early Retirement Benefit . If the Participant has completed 10 Years of Service but has not attained age 55 when the Participant Separates from Service, the Participant shall be entitled to the normal retirement benefit determined under Section 4.1 as adjusted under this Section 4.2(b). Specifically, the following adjustments shall be made:

(1) In determining the normal retirement benefit, the offsets in Sections 4.1(b)(1) and (2) shall be disregarded.


Age at Time Payments Begin		Percentage of Normal Retirement Benefit Payable
55		40.20%
56		43.69%
57		47.54%
58		51.83%
59		56.59%
60		61.90%
61		67.84%
62		74.49%
63		81.98%
64		90.43%
65		100.00%

(3) The non-subsidized early retirement benefit determined after applying subsections (1) and (2) above shall then be reduced by the offsets in Sections 4.1(b)(1) and (2), provided, however, that the offset in Section 4.1(b)(1) shall be determined as the reduced benefit payable as of the Participant’s early retirement date using the early reduction factors then in effect under the Retirement Plan (or other applicable tax-qualified defined benefit pension plan) and the offset in Section 4.1(b)(2) shall be computed in the form of an immediately commencing

annuity using the “applicable interest rate” and “applicable mortality table,” as defined in Section 417(e)(3) of the Code, in effect at that time .

(c) Termination Retirement Benefit . If the Participant has less than 10 Years of Service when the Participant Separates from Service but is 100% vested under the vesting schedule set forth in Section 4.3, the Participant shall be entitled to a termination retirement benefit equal to the normal retirement benefit determined under Section 4.1.

Section 4.3 Vesting

(a) Individuals Who Become Participants After December 31, 2008 . The following vesting schedule applies to any Participant who becomes a Participant after December 31, 2008:


Years of Participation		Vesting Percentage
Less than 5 Years of Participation		0%

5 or more Years of Participation		100%

(b) Individuals Who Became Participants in 2007 or 2008 . The following vesting schedule applies to any Participant who became a Participant in 2007 or 2008:


Years of Service		Vesting Percentage
Less than 5 Years of Service		0%

5 or more Years of Service		100%

(c) Individuals Who Became Participants Prior to January 1, 2007 . The following vesting schedule applies to any Participant who became a Participant before January 1, 2007:


Years of Service		Vesting Percentage
Less than 4 Years of Service		0%

4 or more Years of Service		100%

Section 4.4 Time and Form of Payment of Normal and Subsidized Early Retirement Benefit

(a) Subject to Section 4.10 and the following provisions of this Section 4.4, the Participant’s normal retirement benefit or subsidized early retirement benefit shall commence as soon as practicable (but in any event within ninety (90) days) following the Participant’s Separation from Service in the form of a single life annuity.

(b) A Participant may elect in the form and manner provided by the Committee within thirty (30) days of first commencing participation in the Plan that the normal retirement benefit or subsidized early retirement benefit (i) shall not commence upon the Participant’s Separation from Service but rather shall be paid commencing on (or as soon as practicable but in any event within ninety (90) days following) January 1 of either (A) a calendar year specified by the Participant, provided such calendar year commences after the Participant’s Separation from Service, or (B) a calendar year that begins a number of years (as specified by the Participant) after the Participant’s Separation from Service, and (ii) shall be payable in any form of life annuity benefit available at the time of the election under the Retirement Plan based on the same actuarial assumptions used in determining optional forms of benefits under the Retirement Plan as in effect as of the time of payment.

(c) Before the date a Participant’s life annuity benefit commences pursuant to the foregoing provisions of this Section 4.4, the Participant may elect that payment be made instead in the form of any other life annuity available at the time of the election under the Retirement Plan, provided that such alternative life annuity is treated as an actuarially equivalent life annuity within the meaning of Treasury Regulation § 1.409A-2(b)(2)(ii).

(d) A Participant who has made an election as described in subsection (b), above, or who is deemed (by failing to make an election in accordance with subsection (b), above) to have elected payment in the form of a single life annuity commencing upon Separation from Service, may change such election in the form and manner provided by the Committee provided that, to the extent required by Section 409A of the Code, (i) such election may not take effect until at least twelve (12) months after the date on which the election is made, (ii) the commencement of payment is deferred for a period of not less than five (5) years from the date the first amount was scheduled to be paid, and (iii) the election is made not less than twelve (12) months before the date the first amount was scheduled to be paid.

(e) Notwithstanding the foregoing provisions of this Section 4.4, no payment shall be made until at least six (6) months following the Participant’s Separation from Service, and all amounts that otherwise would have been payable during such six-month period shall be paid (without interest) to the Participant in a lump sum as soon as practicable (but in any event within five (5) business days) following the expiration of such six-month period, and subsequent payments under the Plan shall be made in accordance with the terms of the Plan determined without regard to such six-month delay requirement.

Section 4.5 Time and Form of Payment of Non-Subsidized Early Retirement Benefit

(a) Subject to Section 4.10 and the following provisions of this Section 4.5, any non-subsidized early retirement benefit shall commence on the first day of the month following the Participant’s 55th birthday in the form of a single life annuity.

(b) A Participant may elect in the form and manner provided by the Committee within thirty (30) days of first commencing participation in the Plan that any non-subsidized early retirement benefit payable under this Plan (i) shall not commence on the first day of the month following the Participant’s 55th birthday, but rather shall be paid commencing on (or as soon as practicable but in any event within ninety (90) days following) January 1 of a calendar

year (as specified by the Participant) after the Participant’s 55th birthday, and (ii) shall be payable in any form of life annuity benefit available at the time of the election under the Retirement Plan based on the same actuarial assumptions used in determining optional forms of benefits under the Retirement Plan as in effect as of the time of payment.

(c) Before the date a Participant’s life annuity benefit commences pursuant to the foregoing provisions of this Section 4.5, the Participant may elect that payment be made instead in the form of any other life annuity available at the time of the election under the Retirement Plan, provided that such alternative life annuity is treated as an actuarially equivalent life annuity within the meaning of Treasury Regulation § 1.409A-2(b)(2)(ii).

(d) A Participant who has made an election as described in subsection (b), above, or who is deemed (by failing to make an election in accordance with subsection (b), above) to have elected payment in the form of a single life annuity commencing on the first day of the month following the Participant’s 55th birthday, may change such election in the form and manner provided by the Committee provided that, to the extent required by Section 409A of the Code, (i) such election may not take effect until at least twelve (12) months after the date on which the election is made, (ii) the commencement of payment is deferred for a period of not less than five (5) years from the date the first amount was scheduled to be paid, and (iii) the election is made not less than twelve (12) months before the date the first amount was scheduled to be paid.

(e) Notwithstanding the foregoing provisions of this Section 4.5, no payment shall be made until at least six (6) months following the Participant’s Separation from Service, and all amounts that otherwise would have been payable during such six-month period shall be paid (without interest) to the Participant in a lump sum as soon as practicable (but in any event within five (5) business days) following the expiration of such six-month period, and subsequent payments under the Plan shall be made in accordance with the terms of the Plan determined without regard to such six-month delay requirement.

Section 4.6 Time and Form of Payment of Termination Retirement Benefit

(a) Subject to Section 4.10 and the following provisions of this Section 4.6, any termination retirement benefit shall commence on the first day of the month following the Participant’s Normal Retirement Date in the form of a single life annuity.

(b) Before the date a Participant’s single life annuity commences under Section 4.6(a), the Participant may elect that payment be made in the form of any other life annuity available at the time of the election under the Retirement Plan, provided that such alternative life annuity is treated as an actuarially equivalent life annuity within the meaning of Treasury Regulation § 1.409A-2(b)(2)(ii).

(c) Notwithstanding the foregoing provisions of this Section 4.6, no payment shall be made until at least six (6) months following the Participant’s Separation from Service, and all amounts that otherwise would have been payable during such six-month period shall be paid (without interest) to the Participant in a lump sum as soon as practicable (but in any event within five (5) business days) following the expiration of such six-month period, and subsequent

10.

payments under the Plan shall be made in accordance with the terms of the Plan determined without regard to such six-month delay requirement.

Section 4.7 Transition Elections in 2008

On or before December 31, 2008, the Bank shall provide each current Participant and each terminated, vested Participant who has not begun receiving benefits with an election as to the time and form of benefits payable after 2008. The election may not defer benefits that would otherwise be payable in 2008 and may not cause benefits to be paid in 2008 that would otherwise be payable in a later year. The election as to the time and form of benefits shall otherwise be consistent with the provisions of Sections 4.4 through 4.6, except that if a terminated, vested Participant who has reached age 55 and who has not yet begun receiving his or her tax-qualified pension benefits from the Retirement Plan does not make an election on or before December 31, 2008, as to the time and form of ASB SERP benefits commencing after 2008, such benefits shall commence on the first day of the month coinciding with or next following the date such terminated, vested Participant attains age 65 in the form a single life annuity or other actuarially equivalent life annuity offered under the Retirement Plan at that time, as elected by the Participant before the date the Participant’s single life annuity would otherwise commence.

Section 4.8 Death Benefits

(a) Active Participant Death Benefit . Subject to Section 4.10, if a Participant dies while employed by a Participating Employer or an Associated Company, the Participant’s Spouse shall be entitled to receive a monthly death benefit commencing as soon as practicable (but in any event within ninety (90) days) after the Participant’s death for a ten-year period or until the death of the Participant’s Spouse, if earlier, that is equal to the greater of:

(1) 40% of the Participant’s Final Pay from a Participating Employer; or

(2) The Actuarial Equivalent of the monthly normal retirement benefit the Participant would have been entitled to receive as of the Participant’s Normal Retirement Date based on the formula in Section 4.1, as adjusted for payment prior to Normal Retirement Date in the form of a payment for the lesser of 10 years or the life of the Participant’s Spouse.

(b) Termination Death Benefit . Subject to Section 4.10, if a terminated, vested Participant has attained age 55 and dies prior to the date payment of such Participant’s early retirement or termination retirement benefit commences under Sections 4.2 and 4.4 through 4.7, the Participant’s Spouse, if any, shall be entitled to receive a monthly death benefit commencing as soon as practicable (but in any event within ninety (90) days) after the Participant’s death for a ten-year period or until the death of the Participant’s spouse, if earlier, that is equal to the Actuarial Equivalent of the early retirement or termination retirement benefit the Participant would have been entitled to receive under Section 4.2, as adjusted for payment prior to Normal Retirement Date in the form of a payment for the lesser of 10 years or the life of the Participant’s Spouse.

11.

Section 4.9 Disability Benefits

(a) If a Participant becomes Disabled while employed by a Participating Employer or an Associated Company and before attaining age 65, the Participant shall receive a monthly Disability benefit equal to (X) minus the sum of (Y) and (Z), where:

(X) = 60% of the Participant’s Final Pay from a Participating Employer as of the date the Participant became Disabled;

(Y) = the monthly disability benefit payable to the Participant under the Social Security Act; and

(Z) = all monthly disability benefits payable to the Participant under any other plan or program maintained by a Participating Employer or an Associated Company.

(b) Payment of such monthly Disability benefit shall commence by December 31 of the year in which the Participant is determined to be Disabled (or the 15th day of the 3rd month following the date the Participant is determined to be Disabled, if later) and shall continue until the earlier of the Participant’s death, the date the Participant ceases to be Disabled, or the date the Participant attains age 65.

(c) If a Participant recovers from Disability prior to attaining age 65, all Disability payments made under this Section 4.9 shall cease. If such Participant returns to active employment with a Participating Employer upon the cessation of Disability prior to attaining age 65, the Participant shall be eligible for the other benefits provided under this Article IV, provided the requirements thereof are satisfied. If a Participant does not return to active employment with a Participating Employer after termination of Disability prior to the Participant attaining age 65, the Participant shall be entitled only to the early retirement or termination retirement benefit, if any, the Participant qualifies for under Section 4.2. Any early retirement or termination retirement benefit payable under the previous sentence shall commence as of the Participant’s Normal Retirement Date in the form of a single life annuity. The Participant shall not be given an election to defer commencement of the benefit, but may elect before the Participant’s Normal Retirement Date to have the early retirement or termination retirement benefit paid in the form of any actuarially equivalent life annuity (within the meaning of Treasury Regulation § 1.409A-2(b)(2)(ii)) offered under the Retirement Plan.

(d) A Participant who continues to be Disabled until age 65 shall be entitled to receive, as of the Participant’s Normal Retirement Date, the normal retirement benefit provided under Sections 4.1 and 4.4 based upon the Participant’s Final Average Compensation and Years of Service as of the date the Participant became Disabled.

Section 4.10 Lump-Sum Cashouts of Certain Benefits

In accordance with Sections 4.4 through 4.6, a Participant’s normal or early retirement benefit or termination retirement benefit, as applicable, will be paid in the form of an annuity commencing following the Participant’s Separation from Service or at the time elected by the Participant in accordance with the requirements of the final regulations under Section 409A of the Code and the provisions of this Plan. The death benefits provided under Section 4.8 will

12.

commence following the Participant’s death and will be paid over a 10-year period or until the death of the Participant’s surviving spouse, if earlier. Notwithstanding the foregoing, if the Actuarially Equivalent lump-sum present value of a Participant’s normal or early retirement benefit or termination retirement benefit or of a spousal death benefit, as applicable, is less than or equal to $100,000 (determined at the time the applicable benefit is scheduled to commence), then the applicable benefit shall be paid in the form of a lump sum at the same time the applicable benefit was scheduled to commence.

Section 4.11 Forfeiture in the Event of Termination for Cause

Notwithstanding any other provision of this Plan to the contrary, a Participant shall not be entitled to any benefit under this Plan if a Participating Employer or Associated Company terminates the Participant’s employment for “cause”. For purposes of this Section 4.11, “cause” means the Participant is terminated for violation of the Company’s or Bank’s Code of Conduct.

ARTICLE V

ADMINISTRATION

Section 5.1 The Committee

(a) The Committee shall be responsible for the administration of the Plan. The Committee shall have the sole authority, in its discretion, to adopt, amend, and rescind such rules and procedures as it deems advisable for the administration of the Plan, to construe and interpret the Plan and its provisions, to resolve any ambiguities in the Plan’s provisions, and to make all determinations under the Plan, including determining the rights of Participants and beneficiaries and the amount of any benefits payable under the Plan. All decisions, determinations, and interpretations of the Committee shall be final and binding upon all persons.

(b) The Committee shall have the power to delegate specific responsibilities to any person or group of persons, and such person or group may serve in more than one such delegated capacity. Such delegations may be to employees of the Bank or an Associated Company or to other individuals, all of whom shall serve at the request of the Committee and the Company, and if full-time employees of the Bank or an Associated Company, without compensation. Any such person may resign by delivering a written resignation to the Committee.

(1) Subject to the limitations contained in this Plan, the Committee shall adopt rules for the administration of the Plan as it considers desirable, provided such rules do not conflict with the Plan.

13.

Section 5.2 Expenses

ARTICLE VI

INDEMNIFICATION

ARTICLE VII

CLAIMS PROCEDURES

Section 7.1 Claims Procedure

(a) Written Claim . The Claimant may initiate a claim by submitting to the Bank a written claim for benefits.

(b) Timing of Bank Response . The Bank shall respond to the Claimant within 90 days after receiving the claim. If the Bank determines that special circumstances require additional time for processing the claim, the Bank may extend the response period by an additional 90 days by notifying the Claimant in writing, prior to the end of the initial 90-day period, that an additional period is required. The notice of extension shall set forth the special circumstances and the date by which the Bank expects to render its decision.

14.

(c) Notice of Decision . If the Bank denies part or all of the claim, the Bank shall notify the Claimant in writing of such denial. The Bank shall write the notification in a manner calculated to be understood by the Claimant. The notification shall set forth: (i) the specific reasons for the denial; (ii) a reference to the specific provisions of the Plan on which the denial is based; (iii) a description of any additional information or material necessary for the Claimant to perfect the claim and an explanation of why it is needed; (iv) an explanation of the review procedures in Section 7.2 and the time limits applicable to such procedures; (v) and a statement of the claimant’s right to bring a civil action under ERISA Section 502(a) following an adverse benefit determination on review.

Section 7.2 Review Procedure

If the Bank denies part or all of the claim, the Claimant shall have the opportunity for a full and fair review of the denial by the Committee as follows:

(a) Written Request . In order to initiate the review, the Claimant, within 180 days after receiving the Bank’s notice of denial, may file with the Committee a written request for review. The Claimant shall then have the opportunity to submit written comments, documents, records, and other information relating to the claim. The Bank shall provide the Claimant, upon request and free of charge, reasonable access to, and copies of, all documents, records, and other information relevant (as defined in applicable ERISA regulations) to the Claimant’s claim for benefits.

(c) Timing of Committee Response . The Committee shall respond in writing to such claimant within 60 days after receiving the request for review. If the Committee determines that special circumstances require additional time for processing the claim, the Committee may extend the response period by an additional 60 days by notifying the Claimant in writing, prior to the end of the initial 60-day period, that an additional period is required. The notice of extension must set forth the special circumstances and the date by which the Committee expects to render its decision.

(d) Notice of Decision . The Committee shall notify the Claimant in writing of its decision on review. The Committee shall write the notification in a manner calculated to be understood by the Claimant. The notification shall set forth: (i) the specific reasons for the denial; (ii) a reference to the specific provisions of the Plan on which the denial is based; (iii) a statement that the Claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records, and other information relevant (as defined in applicable ERISA regulations) to the Claimant’s claim for benefits; and (iv) a statement of the Claimant’s right to bring a civil action under ERISA Section 502(a) after exhausting all administrative claims and review procedures in this Article VII.

15.

Section 7.3 Special Rules for Disability Claims

If a claim is made on account of Disability, the time periods for responding to the claim shall be shortened as follows: (a) the 90-day response time with the possibility of a 90-day extension in Section 7.1 shall be shortened to a 45-day response time with the possibility of a 30-day extension, and (b) the 60-day response time with the possibility of a 60-day extension in Section 7.2 shall be shortened to a 45-day response time with the possibility of a 45-day extension. Also, in a review under Section 7.2, the Committee shall identify any medical or vocational expert whose advice was obtained by the Plan in connection with the initial benefit determination, without regard to whether the advice was relied upon. If the review is from an adverse benefit determination that was based in whole or in part on a medical judgment, the Committee shall consult with a health care professional that has appropriate training and experience in the field of medicine involved in the medical judgment and who is neither the individual who was consulted in connection with the adverse benefit determination that is under review nor the subordinate of such individual.

ARTICLE VIII

AMENDMENT, TERMINATION, AND MERGER

Section 8.1 Amendment

The Bank reserves the right to amend the Plan at any time and, to the extent permitted by applicable law, to give any such amendment retroactive effect.

Section 8.2 Termination

The continuation of the Plan is not assumed as a contractual obligation by the Bank or any Participating Employer. Each Participating Employer reserves the right to terminate the Plan with respect to its participation at any time, and the Bank reserves the right to terminate the Plan at any time and for any reason. If the Plan is terminated (in full or in part), the then accrued benefit under this Plan of each affected Participant shall become 100% vested, except to the extent the Participant has not been a Participant for at least thirteen (13) months, in which case the Participant shall become 100% vested if and when the Participant completes such 13-month service requirement.

Section 8.3 Merger, Etc. of the Bank

The Bank shall not sell substantially all of its assets, merge, or consolidate with any other corporation or organization, or permit its business activities to be taken over by another organization, unless and until the succeeding or continuing corporation or other organization expressly assumes the obligations of the Bank under this Plan.

16.

ARTICLE IX

MISCELLANEOUS

Section 9.1 No Right To Employment

Nothing contained in this Plan shall be construed as conferring upon a Participant the right to continue in the service of a Participating Employer as an employee or in any other capacity.

Section 9.2 Inalienability

No Participant or any person having or claiming to have any interest in or under this Plan shall have any right to sell, assign, transfer, convey, hypothecate, anticipate, or otherwise dispose of such interest, and such interest shall not be subject to any liabilities or obligations of, or any bankruptcy proceedings, claims of creditors, attachment, garnishment, execution, levy, or other legal process against such person or such person’s property.

Section 9.3 Facility of Payment

If any Participant or beneficiary eligible to receive payments under this Plan is, in the opinion of the Bank, legally, physically, or mentally incapable of personally receiving and receipting for any payment under this Plan, the Bank may direct payments to such other person, persons, or institutions who, in the opinion of the Bank, are then maintaining or having custody of such payee, until a claim is made by a duly appointed guardian or other legal representative of such payee. Such payments shall constitute a full discharge of the liability of the Plan to the extent thereof.

Section 9.4 Tax Withholding

The payment of any amount under this Plan shall be subject to such income tax, employment tax, and other withholding as the Bank determines is required under applicable law. The Participant shall be liable for any and all taxes applicable to payments under this Plan, and the Bank shall not “gross-up” such payments for taxes.

Section 9.5 Construction of Plan

(b) To the extent not preempted by ERISA, the Plan shall be governed, construed, administered, and regulated according to the laws of the State of Hawaii.

Section 9.6 Forms

All consents, elections, applications, designations, etc. required or permitted under the Plan must be made on forms approved by the Bank, and shall be recognized only if properly completed, executed, and returned to the Bank.

17.

TO RECORD the adoption of this amended and restated Plan, American Savings Bank, F.S.B. has caused this document to be executed this 24 ^th day of October, 2008.


AMERICAN SAVINGS BANK, F.S.B.

By		/s/ Beth Whitehead
Its		Chief Administrative Officer

18.

HEI Exhibit 12.1 (page 1 of 2)

Hawaiian Electric Industries, Inc. and Subsidiaries

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

(unaudited)


Nine months ended September 30	2008 (1)			2008 (2)			2007 (1)			2007 (2)
	(dollars in thousands)
Fixed charges
Total interest charges (3)	$	96,810		$	144,719		$	116,612		$	178,563
Interest component of rentals		4,043			4,043			3,893			3,893
Pretax preferred stock dividend requirements of subsidiaries		2,162			2,162			2,120			2,120

Total fixed charges	$	103,015		$	150,924		$	122,625		$	184,576

Earnings
Pretax income from continuing operations	$	117,276		$	117,276		$	66,675		$	66,675
Fixed charges, as shown		103,015			150,924			122,625			184,576
Interest capitalized		(2,564	)		(2,564	)		(1,840	)		(1,840	)

Earnings available for fixed charges	$	217,727		$	265,636		$	187,460		$	249,411

Ratio of earnings to fixed charges		2.11			1.76			1.53			1.35


Years ended December 31	2007 (1)			2007 (2)			2006 (1)			2006 (2)			2005 (1)			2005 (2)
	(dollars in thousands)
Fixed charges
Total interest charges (3)	$	156,575		$	238,454		$	148,160		$	221,774		$	144,671		$	196,735
Interest component of rentals		5,367			5,367			4,729			4,729			4,133			4,133
Pretax preferred stock dividend requirements of subsidiaries		2,899			2,899			2,974			2,974			2,976			2,976

Total fixed charges	$	164,841		$	246,720		$	155,863		$	229,477		$	151,780		$	203,844

Earnings
Pretax income from continuing operations	$	131,057		$	131,057		$	171,055		$	171,055		$	201,344		$	201,344
Fixed charges, as shown		164,841			246,720			155,863			229,477			151,780			203,844
Interest capitalized		(2,552	)		(2,552	)		(2,879	)		(2,879	)		(2,020	)		(2,020	)

Earnings available for fixed charges	$	293,346		$	375,225		$	324,039		$	397,653		$	351,104		$	403,168

Ratio of earnings to fixed charges		1.78			1.52			2.08			1.73			2.31			1.98

See notes on page 2 of 2.

HEI Exhibit 12.1 (page 2 of 2)

Hawaiian Electric Industries, Inc. and Subsidiaries

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

(unaudited)

(continued)


Years ended December 31	2004 (1)			2004 (2)			2003 (1)			2003 (2)
	(dollars in thousands)
Fixed charges
Total interest charges (3)	$	142,779		$	189,963		$	138,808		$	192,616
Interest component of rentals		3,935			3,935			4,214			4,214
Pretax preferred stock dividend requirements of subsidiaries		2,956			2,956			3,082			3,082
Preferred securities distributions of trust subsidiaries		—			—			16,035			16,035

Total fixed charges	$	149,670		$	196,854		$	162,139		$	215,947

Earnings
Pretax income from continuing operations	$	200,219		$	200,219		$	182,415		$	182,415
Fixed charges, as shown		149,670			196,854			162,139			215,947
Interest capitalized		(2,542	)		(2,542	)		(1,914	)		(1,914	)

Earnings available for fixed charges	$	347,347		$	394,531		$	342,640		$	396,448

Ratio of earnings to fixed charges		2.32			2.00			2.11			1.84

(1)	Excluding interest on ASB deposits.

(2)	Including interest on ASB deposits.

(3)	Interest on nonrecourse debt from leveraged leases is not included in total interest charges nor in interest expense in HEI’s consolidated statements of income.

For purposes of calculating the ratio of earnings to fixed charges, “earnings” represent the sum of (i) pretax income from continuing operations (before adjustment for undistributed income or loss from equity investees) and (ii) fixed charges (as hereinafter defined, but excluding capitalized interest). “Fixed charges” are calculated both excluding and including interest on ASB’s deposits during the applicable periods and represent the sum of (i) interest, whether capitalized or expensed, but excluding interest on nonrecourse debt from leveraged leases which is not included in interest expense in HEI’s consolidated statements of income, (ii) amortization of debt expense and discount or premium related to any indebtedness, whether capitalized or expensed, (iii) the estimate of the interest within rental expense, (iv) the non-intercompany preferred stock dividend requirements of HEI’s subsidiaries, increased to an amount representing the pretax earnings required to cover such dividend requirements and (v) in 2003 and prior years when the trust subsidiaries were consolidated, the preferred securities distribution requirements of trust subsidiaries.

HEI Exhibit 31.1

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

I, Constance H. Lau, certify that:

1.	I have reviewed this report on Form 10-Q for the quarter ended September 30, 2008 of Hawaiian Electric Industries, Inc. (“registrant”);

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 4, 2008

/s/ Constance H. Lau

Constance H. Lau

President and Chief Executive Officer

HEI Exhibit 31.2

Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Curtis Y. Harada (HEI Chief Financial Officer)

I, Curtis Y. Harada, certify that:

1.	I have reviewed this report on Form 10-Q for the quarter ended September 30, 2008 of Hawaiian Electric Industries, Inc. (“registrant”);

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(a)

(b)

(c)

(d)

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 4, 2008

/s/ Curtis Y. Harada

Curtis Y. Harada

Controller and Acting Financial Vice President,

Treasurer and Chief Financial Officer

HEI Exhibit 32.1

Hawaiian Electric Industries, Inc.

Written Statement of Chief Executive Officer Furnished Pursuant to

18 U.S.C. Section 1350,

as Adopted by

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of Hawaiian Electric Industries, Inc. (HEI) on Form 10-Q for the quarter ended September 30, 2008 as filed with the Securities and Exchange Commission (the Report), I, Constance H. Lau, Chief Executive Officer of HEI, certify, pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1)	The Report fully complies with the requirements of section 13(a) of the Securities Exchange Act of 1934; and

(2)	The consolidated information contained in the Report fairly presents, in all material respects, the financial condition as of September 30, 2008 and results of operations for the three and nine months ended September 30, 2008 of HEI and its subsidiaries.

/s/ Constance H. Lau

Constance H. Lau

President and Chief Executive Officer

Date: November 4, 2008

A signed original of this written statement required by Section 906 has been provided to HEI and will be retained by HEI and furnished to the Securities and Exchange Commission or its staff upon request.

HEI Exhibit 32.2

Hawaiian Electric Industries, Inc.

Written Statement of Chief Financial Officer Furnished Pursuant to

18 U.S.C. Section 1350,

as Adopted by

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of Hawaiian Electric Industries, Inc. (HEI) on Form 10-Q for the quarter ended September 30, 2008 as filed with the Securities and Exchange Commission (the Report), I, Curtis Y. Harada, Chief Financial Officer of HEI, certify, pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1)	The Report fully complies with the requirements of section 13(a) of the Securities Exchange Act of 1934; and

(2)	The consolidated information contained in the Report fairly presents, in all material respects, the financial condition as of September 30, 2008 and results of operations for the three and nine months ended September 30, 2008 of HEI and its subsidiaries.

/s/ Curtis Y. Harada

Curtis Y. Harada

Controller and Acting Financial Vice President, Treasurer and Chief Financial Officer

Date: November 4, 2008

HEI Exhibit 99.1

November 4, 2008


Contact:	Suzy P. Hollinger	(808) 543-7385 Telephone
	Manager, Treasury and Investor Relations	(808) 203-1155 Facsimile
		E-mail: shollinger@hei.com

HAWAIIAN ELECTRIC INDUSTRIES, INC. REPORTS SOLID THIRD QUARTER 2008 RESULTS

HONOLULU — Hawaiian Electric Industries, Inc. (NYSE - HE) today reported consolidated net income for the third quarter of 2008 of $37.3 million, or $0.44 per share, compared to $19.9 million, or $0.24 per share for the third quarter of 2007.

“Our earnings showed significant improvement over our unusually low results in the third quarter of 2007, which included a utility customer refund accrual that reduced those results by $0.10 a share,” said Constance H. Lau, HEI president and chief executive officer. “Our utilities continued to regain financial strength due to interim rate relief received primarily in the last quarter of 2007. The bank’s earnings improved 31% quarter-over-quarter, benefitting from a steeper yield curve, continued good credit quality and lower expenses resulting from performance improvement initiatives. Additionally, holding and other companies’ losses in the quarter were lower than in the same period in 2007 primarily due to lower interest expense,” noted Lau.

UTILITY RESULTS

Electric utility net income for the third quarter of 2008 was $25.9 million compared with $12.9 million for the same quarter in 2007 and $23.7 million for the same quarter in

Hawaiian Electric Industries, Inc. News Release

November 4, 2008

Page 2

2006. “Third quarter earnings a year ago were unusually low as our Oahu utility accrued an $8.3 million, or $0.10 per share, net-of-tax refund related to its 2005 test year rate case and awaited rate increases to recover and earn a return on reliability investments and to recover higher operating costs,” said Lau.

Kilowatthour sales were lower by 2.6% quarter-over-quarter due to greater customer conservation and a slowing economy. These two factors are expected to reduce our 2008 and 2009 sales forecasts slightly below original projections. “Clearly, with the economic downturn and the dramatic impact of rising fuel costs on electricity prices during the quarter, customers have redoubled their efforts to conserve energy. In view of the economic downturn, we expect this conservation trend to continue even with recent declines in the fuel price component of our customer bills,” said Lau.

Other operations and maintenance (O&M) expenses were up 5% quarter-over-quarter as higher operations expenses for customer efficiency programs and production operations were partially offset by lower production maintenance expenses resulting primarily from changes in generating unit overhaul schedules. The expected increase in full-year 2008 O&M expenses continues to be roughly 6% over 2007, but actual levels could be influenced by a number of factors that cannot be predicted.

The utility also recorded $1.1 million in higher quarter-over-quarter depreciation expenses due to 2007 plant additions.

Hawaiian Electric Industries, Inc. News Release

November 4, 2008

Page 3

BANK RESULTS

Bank net income for the third quarter of 2008 was $15.4 million, compared to $11.7 million for the same quarter last year. Return on assets in the third quarter of 2008 was 1.11% compared to 0.69% in the third quarter of 2007.

Net interest income in the third quarter of 2008 was $52.3 million compared to $47.7 million in the third quarter of 2007. The impact of lower interest expense, primarily due to lower balances of borrowings and lower rates on deposits and borrowings, more than offset the decline in interest income primarily from lower investment balances and lower yields on loans. The lower balances of investments and borrowings in the third quarter of 2008 were a result of the balance sheet restructuring executed in June 2008. Net interest margin expanded to 4.08% in the third quarter of 2008, compared with 2.97% in the third quarter of 2007.

“We are pleased with the bank’s third quarter results,” said Lau. “In spite of the continued volatility in the financial and credit markets during the quarter, the bank continued to perform well. Third quarter results show the improvements in net interest margin and return on assets we expected to achieve from the June balance sheet restructuring.”

The bank recorded a $2.0 million provision for possible loan losses in the third quarter, compared to a $2.7 million provision in the third quarter of 2007. “The overall credit quality of the bank’s loan portfolio remains good. However, we are seeing the effects of the slowing economy in modestly rising delinquencies and the reclassification of some commercial loans. We remain cautious and continue to actively monitor our loan portfolios,” added Lau.

Hawaiian Electric Industries, Inc. News Release

November 4, 2008

Page 4

Noninterest income in the third quarter of 2008 was $16.7 million compared to $17.2 million in the same quarter in 2007. Higher fee income from deposit liabilities was more than offset by lower fee income from other financial services, other financial products and other income.

Noninterest expense was $1.3 million lower in the third quarter of 2008 than in the third quarter of 2007. Lower services and other expenses were partially offset by an increase in compensation and benefits expense quarter over quarter. The $3.0 million increase in compensation and benefits was primarily due to a $0.9 million accrual for incentive compensation in the third quarter of 2008, compared with a $1.4 million reversal of accrued incentive compensation in the third quarter of 2007.

HOLDING AND OTHER COMPANIES’ RESULTS

The holding and other companies’ net losses were $4.1 million in the third quarter of 2008 compared with $4.7 million in the third quarter of 2007.

WEBCAST AND TELECONFERENCE

Hawaiian Electric Industries, Inc. will conduct a webcast and teleconference call to review its third quarter 2008 earnings on Wednesday, November 5, 2008, at 8:00 a.m. Hawaii Time (1:00 p.m. Eastern Time). The event can be accessed through HEI’s website at http://www.hei.com or by dialing (800) 299-7089, passcode: 86433944 for the teleconference call.

An online replay of the webcast will be available at the same website beginning about two hours after the event. Replays of the teleconference call will also be available

Hawaiian Electric Industries, Inc. News Release

November 4, 2008

Page 5

approximately two hours after the event through November 19, 2008, by dialing (888) 286-8010, passcode: 98026401.

Representing management will be Constance H. Lau, president and chief executive officer, Hawaiian Electric Industries, Inc. and chairman, Hawaiian Electric Company, Inc.; and Timothy K. Schools, president, American Savings Bank, F. S. B.

HEI supplies power to over 400,000 customers or 95% of Hawaii’s population through its electric utilities, Hawaiian Electric Company, Inc., Hawaii Electric Light Company, Inc. and Maui Electric Company, Ltd. and provides a wide array of banking and other financial services to consumers and businesses through American Savings Bank, F.S.B., one of Hawaii’s largest financial institutions.

FORWARD-LOOKING STATEMENTS

This release may 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 (including future revenues, expenses, earnings or losses or growth rates), ongoing business strategies or prospects and possible future actions, which may be provided by management, 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 assumptions about HEI and its subsidiaries, the performance of the industries in which they do business and economic and market factors,

Hawaiian Electric Industries, Inc. News Release

November 4, 2008

Page 6

among other things. These forward-looking statements are not guarantees of future performance.

Forward-looking statements in this release should be read in conjunction with the “Forward-Looking Statements” discussion (which is incorporated by reference herein) set forth on page iv of HEI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, and in HEI’s future periodic reports that discuss important factors that could cause HEI’s results to differ materially from those anticipated in such statements. Forward-looking statements speak only as of the date of this release.

###

Hawaiian Electric Industries, Inc. (HEI) and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)


	Three months ended September 30,						Nine months ended September 30,						Twelve months ended September 30,
(in thousands, except per share amounts)	2008			2007			2008			2007			2008			2007
Revenues
Electric utility	$	827,788		$	567,615		$	2,139,798		$	1,508,005		$	2,738,107		$	2,014,034
Bank		87,675			105,507			279,469			317,493			387,471			419,960
Other		(32	)		339			(164	)		2,749			1,696			1,332

		915,431			673,461			2,419,103			1,828,247			3,127,274			2,435,326

Expenses
Electric utility		775,941			536,249			1,981,572			1,434,858			2,522,443			1,908,246
Bank		62,983			86,960			262,406			260,824			343,067			348,485
Other		2,378			2,235			8,648			10,698			13,422			13,568

		841,302			625,444			2,252,626			1,706,380			2,878,932			2,270,299

Operating income (loss)
Electric utility		51,847			31,366			158,226			73,147			215,664			105,788
Bank		24,692			18,547			17,063			56,669			44,404			71,475
Other		(2,410	)		(1,896	)		(8,812	)		(7,949	)		(11,726	)		(12,236	)

		74,129			48,017			166,477			121,867			248,342			165,027

Interest expense–other than on deposit liabilities and other bank borrowings		(19,345	)		(19,589	)		(56,780	)		(59,382	)		(75,954	)		(78,534	)
Allowance for borrowed funds used during construction		967			656			2,564			1,840			3,276			2,460
Preferred stock dividends of subsidiaries		(471	)		(474	)		(1,417	)		(1,420	)		(1,887	)		(1,893	)
Allowance for equity funds used during construction		2,426			1,336			6,432			3,770			7,881			5,144

Income before income taxes		57,706			29,946			117,276			66,675			181,658			92,204
Income taxes		20,425			10,065			40,892			22,481			64,689			31,893

Net income	$	37,281		$	19,881		$	76,384		$	44,194		$	116,969		$	60,311

Basic earnings per common share	$	0.44		$	0.24		$	0.91		$	0.54		$	1.40		$	0.74

Diluted earnings per common share	$	0.44		$	0.24		$	0.91		$	0.54		$	1.39		$	0.74

Dividends per common share	$	0.31		$	0.31		$	0.93		$	0.93		$	1.24		$	1.24

Weighted-average number of common shares outstanding		84,625			82,481			84,052			81,949			83,788			81,781

Adjusted weighted-average shares		84,842			82,640			84,182			82,180			83,906			81,984

Net income (loss) by segment
Electric utility	$	25,932		$	12,875		$	77,949		$	23,978		$	106,127		$	36,985
Bank		15,405			11,731			11,888			35,909			29,086			45,176
Other		(4,056	)		(4,725	)		(13,453	)		(15,693	)		(18,244	)		(21,850	)

Net income	$	37,281		$	19,881		$	76,384		$	44,194		$	116,969		$	60,311

This information should be read in conjunction with the consolidated financial statements and the notes thereto for the year ended December 31, 2007 (included in HEI’s Form 8-K dated February 21, 2008) and the consolidated financial statements and the notes thereto in HEI’s Quarterly Reports on SEC Form 10-Q for the quarters ended March 31, 2008, June 30, 2008 and September 30, 2008 (when filed). Results of operations for interim periods are not necessarily indicative of results to be expected for future interim periods or the full year.

Hawaiian Electric Company, Inc. (HECO) and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)


	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2008			2007			2008			2007
Operating revenues	$	826,124		$	561,720		$	2,135,265		$	1,499,766

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

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

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

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

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

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

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

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

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

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

OTHER ELECTRIC UTILITY INFORMATION
Kilowatthour sales (millions)		2,593			2,663			7,478			7,568
Cooling degree days (Oahu)		1,530			1,566			3,779			3,666
Average fuel oil cost per barrel	$	133.99		$	74.78		$	111.37		$	65.52

This information should be read in conjunction with the consolidated financial statements and the notes thereto for the year ended December 31, 2007 (included in HECO Exhibit 99.1 to HECO’s Form 8-K dated February 21, 2008) and the consolidated financial statements and the notes thereto in HECO’s Quarterly Reports on SEC Form 10-Q for the quarters ended March 31, 2008, June 30, 2008 and September 30, 2008 (when filed). Results of operations for interim periods are not necessarily indicative of results to be expected for future interim periods or the full year.

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

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)


	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2008		2007		2008			2007
Interest and dividend income
Interest and fees on loans	$	61,100	$	61,817	$	186,312		$	182,191
Interest and dividends on investment and mortgage-related securities		9,898		26,497		57,078			85,090

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

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

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

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

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

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

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

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

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

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

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

Net interest margin (%)		4.08		2.97		3.49			3.05

This information should be read in conjunction with the consolidated financial statements and the notes thereto for the year ended December 31, 2007 (included in HEI Exhibit 13 to HEI’s Form 8-K dated February 21, 2008) and the consolidated financial statements and the notes thereto in HEI’s Quarterly Reports on SEC Form 10-Q for the quarters ended March 31, 2008, June 30, 2008 and September 30, 2008 (when filed). Results of operations for interim periods are not necessarily indicative of results to be expected for future interim periods or the full year.

HECO Exhibit 10.9

ASSIGNMENT AND ACCEPTANCE AGREEMENT

Assignment and Acceptance Agreement (as the same may be amended, supplemented or otherwise modified from time to time, this “Assignment and Acceptance Agreement” ), dated as of September 18, 2008 by and between Lehman Brothers Bank , FSB a Lender under the Credit Agreement referred to below (the “Assignor” ), and Bank Hapoalim BM (the “Assignee” ).

R E C I T A L S

A. Reference is made to the Credit Agreement, dated as of March 31, 2006, among Hawaiian Electric Company, Inc., a Hawaii corporation (the “ Borrower” ), the Lenders party thereto and The Bank of New York Mellon, formerly The Bank of New York , as Administrative Agent (as the same may be amended, supplemented or otherwise modified from time to time, the “Credit Agreement” ). Capitalized terms used herein which are not otherwise defined herein shall have the respective meanings ascribed thereto in the Credit Agreement.

B. Pursuant to the Credit Agreement and subject to the limitations set forth therein the Credit Parties agreed to make the Loans under the terms and conditions therein set forth.

C. The amount of the Assignor’s Revolving Commitment (without giving effect to the assignment effected hereby or to other assignments thereof which have not yet become effective) is specified in Item 1 of Schedule 1 hereto. The outstanding principal amount of the Assignor’s Revolving Loans without giving effect to the assignment effected hereby or to other assignments thereof which have not yet become effective, is specified in Item 2 of Schedule 1 hereto.

D. The Assignor wishes to sell and assign to the Assignee, and the Assignee wishes to purchase and assume from the Assignor, (i) the portion of the Assignor’s rights and obligations under the Loan Documents, including its Revolving Commitment specified in Item 3 of Schedule 1 hereto (the “Assigned Commitment” ), and (ii) the portion of the Assignor’s Revolving Loans specified in Item 4 of Schedule 1 hereto (the “Assigned Loans” ).

The parties agree as follows:

Assignment

Commitment. As full consideration for the sale of the Assigned Loans, the Assignee shall pay to the Assignor on the date hereof an amount equal to the principal amount of the Assigned Loans or such other amount as shall be agreed upon by the Assignor and the Assignee (the “Purchase Price” ), and the Assignor shall pay the fee payable to the Administrative Agent pursuant to Section 10.04(b) of the Credit Agreement.

Representations and Warranties

Effect of Assignment.

and the Assignee shall make all appropriate adjustments directly between themselves with respect to amounts under the Loan Documents which accrued prior to the date hereof and which were paid thereafter.

Method of Payment

Notices

Miscellaneous

(b) Section headings have been inserted herein for convenience only and shall not be construed to be a part hereof.

(f) This Assignment and Acceptance Agreement shall be binding upon and inure to the benefit of the Assignor and the Assignee and their respective successors and permitted assigns, except that neither party may assign or transfer any of its rights or obligations hereunder (i) without the prior written consent of the other party, and (ii) in contravention of the Credit Agreement.

(h) This Assignment and Acceptance Agreement shall become effective on the date it has been executed by the Assignor, the Assignee, the Administrative Agent, and, unless an Event of Default has occurred and is continuing, the Borrower.

[Signature Pages To Follow]


Lehman Brothers Bank, FSB , as Assignor

By:		/s/ Tina Chen
Name:		Tina Chen
Title:		Authorized Signatory


Bank Hapoalim BM , as Assignee

By:		/s/ Shaun Breidbart/Charles McLaughlin
Name:		Shaun Breidbart/Charles McLaughlin
Title:		Vice President/Senior Vice President

Consented to and Accepted this 18th day:

of September, 2008

THE BANK OF NEW YORK MELLON, as Administrative Agent and Issuing Bank


By:		/s/ Ronald R. Reedy
Name:		Ronald R. Reedy
Title:		Managing Director

Consented to this 17 ^th day:

of September, 2008

HAWAIIAN ELECTRIC COMPANY, INC.


By:		/s/ Tayne S. Y. Sekimura
Name:		Tayne S. Y. Sekimura

By:		/s/ Lorie Ann Nagata
Name:		Lorie Ann Nagata

SCHEDULE 1

ASSIGNMENT AND ACCEPTANCE AGREEMENT,

dated as of September 18, 2008,

between Lehman Brothers Bank, FSB as Assignor

and

Bank Hapoalim BM, as Assignee,

relating to the

Credit Agreement, dated as of March 31, 2006,

by and among

Hawaiian Electric Company, Inc.,

the Lenders party thereto

and

The Bank of New York Mellon, formerly The Bank of New York , as Administrative Agent


Item 1.	*Amount of Assignor’s Aggregate Commitment :**

	(a) Revolving Commitment	$	9,545,454.55

Item 2.	Outstanding principal balance/amount of the Assignor’s Loans *:

	(a) Revolving Loans consisting of:
	ABR Borrowing	$	00.00
	Eurodollar Borrowing	$	00.00

Item 3.	Amount of Revolving Commitment and/or Letter of Credit Commitment being assigned:

	(a) Revolving Commitment	$	9,545,454.55

Item 4.	Outstanding principal balance/amount of the Revolving Loans being assigned:

	(a) Revolving Loans consisting of:
	ABR Borrowing	$	0.00
	Eurodollar Borrowing	$	0.00

HECO Exhibit 10.10

[HECO letterhead]

June 13, 2008

CONFIDENTIAL

Mr. T. Michael May

President and Chief Executive Officer

Hawaiian Electric Company, Inc.

P. O. Box 2750

Honolulu, Hawaii 96840

Re:

Retirement Understanding for T. Michael May

Dear Mike:

In recognition of your 17 years of service to Hawaiian Electric Company and at your request, I have agreed to memorialize the terms of your retirement from the Company, which terms we have discussed in detail. Those terms are set forth below.

First, you can continue as President and CEO and a director of HECO (the “Company”) until August 1, 2008, at which point in time you will step down from those positions. However, as chair of the board, I will begin working with you immediately on transition matters and effectively oversee the HECO management team and the Company’s business affairs.

Second, you will remain an employee of HECO, at your current base salary compensation level, until on or before February 1, 2009 (your anniversary date), at which time you will retire, with the understanding that you will take all remaining weeks of accrued vacation prior to your retirement date.

Third, upon your retirement (or as soon thereafter as 2008 financial results can be finalized and EICP awards by the Compensation Committee made), you will receive a payment of $348,600 offset by the amount of EICP payout you receive for 2008 (but not less than zero). As an employee throughout 2008, you will be eligible to receive EICP and LTIP payouts, if any, in accordance with the terms of that plan. Any EICP payout that you receive for 2008 shall be considered under the terms of SERP. If a 2008 EICP payout of “target” is achieved, it would have a specific impact (“Impact”) on the calculation of your SERP benefits. In the event that a 2008 EICP payout of at least “target” is not achieved, then the Company will purchase an annuity for you in an amount equivalent to the shortfall that would exist by you not receiving the Impact. [For example, if the Impact would result in an additional benefit of $30,000/year in SERP benefits, and if you only received 80% of the EICP target, then the Company would purchase for you an annuity equivalent to $6000/year (which reflects the aforesaid shortfall).]


CONFIDENTIAL
T. Michael May		Re: Retirement Understanding for T. Michael May
June 13, 2008
Page 2

Fourth, the following Company reimbursements or perquisites will continue until your retirement date: (i) the monthly fees of your club memberships (OCC and Plaza Club); (ii) your current parking space; and (iii) your current automobile and gas allowance. In addition, the company will assist you in removing personal effects from the office and reimburse you for packing and moving expenses.

Fifth, the Company will provide you with office space and secretarial assistance, if needed, through your retirement date; however, you shall occupy your current office only until August 1, 2008. It is not expected in the terms of your continued employment that you report for work at specified times and location, but be on call and available from time to time to support the Company and assist with the leadership transition.

Sixth, the Company shall reimburse you for the customary expenses you will incur while traveling to and attending two conferences – the EEI conference for CEOs to be held in October/November of this year, and the ABB conference to be held in September in which you are a scheduled speaker. With respect to both conferences, you shall represent yourself as the retired CEO of HECO.

Finally, it is understood that you shall cooperate fully with the Company and the executive search that will be underway, and assist the new CEO when he/she arrives as needed. Further, you recognize that as long as you are an employee of the Company, you are subject to compliance with the Company’s Code of Conduct and other policies and procedures.

I believe that the foregoing accurately reflects our understanding regarding the terms of your departure and retirement. Please acknowledge this by signing below where indicated and return a copy to me.

Sincerely,

/s/ Constance H. Lau

Constance H. Lau

Chairman of the Board

Hawaiian Electric Company, Inc.

Acknowledged:

/s/ T. Michael May

T. Michael May

HECO Exhibit 10.11

HAWAIIAN ELECTRIC INDUSTRIES, INC.

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

Addendum for T. Michael May

WHEREAS, Mr. May is a Participant in the Hawaiian Electric Industries, Inc. Supplemental Executive Retirement Plan (the “HEI SERP”) and is expected to retire from Hawaiian Electric Company, Inc. (“HECO”);

WHEREAS, in June 2008 HECO and Mr. May agreed that he would remain an employee of HECO until on or before February 1, 2009 (his anniversary date) at which time he would retire;

WHEREAS, Mr. May would prefer to set his retirement so that he will remain an employee of HECO until December 31, 2008, which would be his last day of employment with HECO;

WHEREAS, HECO is amenable to Mr. May’s last day of employment being December 31, 2008 rather than February 1, 2009;

WHEREAS, under the terms of the HEI SERP, any bonus earned under the Hawaiian Electric Industries, Inc. Executive Incentive Compensation Plan (“EICP”) is included in the definitions of “Compensation” and “Final Average Compensation” for purposes of determining a Participant’s normal retirement income;

WHEREAS, if Mr. May’s target goals for his 2008 EICP were achieved, he would receive a payout of $348,600;

WHEREAS, in June 2008 HECO agreed to purchase an annuity for Mr. May in 2009 to cover the difference, if any, between (a) what Mr. May’s SERP benefit would be if Mr. May’s EICP target payout for 2008 is achieved and (b) Mr. May’s actual SERP benefit if Mr. May’s target EICP payout for 2008 is not achieved;

WHEREAS, the Board of Directors of Hawaiian Electric Industries, Inc. (the “Board”) has reviewed the June 2008 agreement between HECO and Mr. May and, rather than have HECO provide Mr. May with an annuity if Mr. May’s target EICP payout is not achieved in 2008, the Board would prefer to provide Mr. May with an HEI SERP benefit based on the assumption that part of his compensation for 2008 will be the greater of (a) his actual EICP payout for 2008 or (b) a discretionary bonus for 2008 of $348,600; and

WHEREAS, Mr. May would also prefer to have a discretionary bonus payout of $348,600 for 2008 included as a floor in his HEI SERP calculation rather than receiving an annuity in 2009;

NOW, THEREFORE, Hawaiian Electric Industries, Inc., the sponsor of the HEI SERP, and Mr. May agree as follows:

Mr. May’s HEI SERP benefit will be calculated by including as part of his compensation for 2008 the greater of (a) his actual EICP payout for 2008 or (b) a discretionary bonus for 2008 of $348,600. If his actual EICP payout is less than $348,600, then the maximum aggregate amount of payout or payments described in (a) and/or (b) of the preceding sentence that will included as part of his compensation in calculating his SERP benefit will be $348,600.

The June agreement is amended so that (a) Mr. May’s last day of employment with HECO will be December 31, 2008 at which time he will retire with the understanding that he will have taken all remaining weeks of his accrued vacation by that date, and (b) HECO will not provide Mr. May with an annuity if Mr. May’s target EICP payout for 2008 is not achieved.

Hawaiian Electric Industries, Inc. and Mr. May have executed this Addendum to the HEI SERP this 28th day of October, 2008.


HAWAIIAN ELECTRIC INDUSTRIES, INC.

By:	/s/ Constance H. Lau	/s/ T. Michael May
Its:	President & CEO	T. Michael May

By:	/s/ Chet A. Richardson
Its:	Vice President

HECO Exhibit 10.12

ENERGY AGREEMENT AMONG THE STATE OF HAWAII, DIVISION OF CONSUMER

ADVOCACY OF THE DEPARTMENT OF COMMERCE AND CONSUMER AFFAIRS, AND

THE HAWAIIAN ELECTRIC COMPANIES

The signatories to this agreement are the Governor of the State of Hawaii; the State Department of Business, Economic Development and Tourism; Hawaiian Electric Company, Hawaii Electric Light Company, Maui Electric Company (“Hawaiian Electric Companies”); and the Division of Consumer Advocacy of the Department of Commerce and Consumer Affairs.

On behalf of the people of Hawaii, we believe that the future of Hawaii requires that we move more decisively and irreversibly away from imported fossil fuel for electricity and transportation and towards indigenously produced renewable energy and an ethic of energy efficiency. The very future of our land, our economy and our quality of life is at risk if we do not make this move and we do so for the future of Hawaii and of the generations to come.

The islands of Hawaii have abundant natural resources, including wind, sunshine, ocean and geothermal sources for electricity generation, and land for energy crops that can be refined into biofuels to address electricity and transportation needs. Economic and culturally sensitive use of natural resources can achieve energy supply security and price stability for the people of Hawaii, as well as significant environmental and economic opportunities and benefits. Successfully developing Hawaii’s energy economy will make the State a global model for achieving a sustainable, clean, flexible, and economically vibrant energy future.

We commit to being open and truthful with our community about the investment necessary to transition to a clean energy future, the importance of making it, and the time it will take to be successful. We accept that the transition to this clean energy future will require significant public and private investment with impacts on Hawaii’s ratepayers and taxpayers and, we expect to achieve long-term benefits that outweigh the costs of such investments.

As we move from central-station, oil-based firm power to a much more renewable and distributed and intermittent powered system, we accept that the operating risks of the Hawaiian Electric Companies will increase which may potentially affect customers. Thus, we recognize the need to assure that Hawaii preserves a stable electric grid to minimize disruption to service quality and reliability. In addition, we recognize the need for a financially sound electric utility. Both are vital components for our achievement of an independent renewable energy future.

We commit to take steps to reduce the demand for electricity and increase the efficiency of energy that we do use both to reduce the costs to the public and to reduce the level of electrical generation. At the same time, we recognize that a system of utility regulation will be needed to assure that Hawaii preserves a stable electric grid and a financially sound electric utility as vital components of our renewable energy future.

We will strive to assure that this process to achieve the HCEI goals and objectives will be directed towards providing ratepayer benefits, including long term price stability, and ultimately lower cost than would be incurred using imported fossil fuels.

We also commit to incorporate new metrics for measurement and oversight systems that monitor our progress in reducing our use of imported fossil fuel, while increasing our efficiency and our use of renewable energy to meet Hawaii’s electrical energy demand.

We commit ourselves to a system of utility regulation that will transform our major utility from a traditional sales-based company to an energy services provider that retains its obligation to serve our public with reliable energy, strives to source and integrate greener and lower cost generation, and moves us to an energy independent future.

And finally, we commit to working together in good faith, openness and in the spirit of cooperation and collaboration to achieve the objectives and goals set forth in this agreement.


/s/ Linda Lingle		/s/ Constance H. Lau
Linda Lingle		Constance H. Lau
Governor		Chairman of the Board
State of Hawaii		Hawaiian Electric Company, Inc.


/s/ Theodore E. Liu		/s/ Robert A. Alm
Theodore E. Liu		Robert A. Alm
Director		Executive Vice President
Department of Business Economic Development and Tourism		Hawaiian Electric Company, Inc.

/s/ Catherine P. Awakuni

Catherine P. Awakuni

Executive Director

Division of Consumer Advocacy

Department of Commerce and Consumer Affairs

Witnessed By:


/s/ William Parks		/s/ Maurice H. Kaya
William Parks		Maurice H. Kaya
U.S. Department of Energy		Technical Director
		Hawaii Renewable Energy Development Venture

1 Wind Power for Hawaii

The Hawaiian Electric Companies are committed to integrating the maximum attainable amount of wind energy on their systems.

Furthermore, the Hawaiian Electric Companies are committed to prudently negotiate purchase power agreements and evaluate integration investment costs for the benefit of the Hawaiian Electric Companies’ ratepayers.

To accelerate the addition of clean renewable energy resources for the residents of Oahu, Hawaiian Electric is negotiating Power Purchase Agreements (“PPA”) with several independent power producers (“IPP”) totaling up to approximately 135 MW of renewable energy (collectively the “Grandfathered Projects”), which includes a 30 MW wind farm located on the north shore of Oahu.

In addition to pursuing these Grandfathered Projects, Hawaiian Electric has also issued a Request for Proposals for Renewable Energy Projects (“RE RFP”) seeking to contract for an additional 100 MW of renewable energy for Oahu. The RE RFP is part of a structured competitive procurement process established by the Commission (“Competitive Bidding Framework”) with the intent to enable Hawaiian Electric to obtain viable renewable energy generation at a competitive and reasonable cost for the benefit of all ratepayers. Hawaiian Electric believes that much of the developable wind energy resources located on Oahu (understood to be in the range of approximately 100 MW) has the opportunity to be realized in the near term as a direct result of the Grandfathered Projects and the RE RFP activities.

Wind power is a commercially proven source of renewable energy today that, while limited on Oahu, is abundant on the neighbor islands with combined resource potential across the State thought to be in excess of 1,000 MW. To achieve substantially greater use of wind power on Oahu where most of the electric power in the State is consumed, it is necessary to transmit the wind power produced on the other islands by undersea cable systems ¹ to Oahu. Several developers proposing large-scale wind farm projects located on the islands of Lanai and Molokai, ranging in size of up to roughly 400 MW each, have notified Hawaiian Electric of their intent to submit a proposal in response to the RE RFP.

In order to facilitate a future in which the abundant, sustainable and indigenous wind resources of our islands supply a significant portion of the total energy demand on Oahu, the parties commit to the following:

¹	Undersea cable systems are comprised of all facilities between the Oahu and the neighbor islands’ AC transmission systems to transfer power between each island’s grids.

1. Hawaiian Electric commits to integrate, with the assistance of the State to accelerate the commitment, up to 400 MW of wind power into the Oahu electrical system that is produced by one or more wind farms located on either the island of Lanai or Molokai and transmitted to Oahu via undersea cable systems (the “Big Wind” projects). This accelerated process shall in no way limit the longer term incorporation of additional neighbor island renewable energy projects should those future projects and cost of integration prove feasible and prudent to ratepayers.

2. Hawaiian Electric and the State commit to accelerate the addition of new clean renewable energy resources on Oahu. To that end, the parties recognize that the ongoing efforts related to the Grandfathered Projects and the Oahu RE RFP currently in progress provide the best near-term opportunity to add up to 235 MW of new clean renewable energy resources located on Oahu. Hawaiian Electric commits to continue negotiations for the purchase of renewable energy from Grandfathered Projects and to efficiently complete the Oahu RE RFP. The State commits to support, facilitate and help expedite these ongoing Oahu or Oahu related activities and processes, including the successful development of the resulting Oahu or Oahu related renewable energy projects.

3. To facilitate the early adoption of both the Oahu projects and one or more of the neighbor island wind farm, Hawaiian Electric, with support from the State, commits to work together with the developers of these Big Wind projects and the Commission to bifurcate their project proposals from the ongoing Oahu RE RFP. The bifurcated RFP process to evaluate and select the best Big Wind project or projects, will be led by Hawaiian Electric, with support from the State. Selection is contemplated to be conducted in conformance with the Competitive Bidding Framework using data submitted by developers in September 2008. The State will support Hawaiian Electric in the wind farm evaluation and selection process.

4. Hawaiian Electric also agrees to provide $100,000 in funding to model the Molokai grid and to make efficiency recommendations to the island residents. (A similar program is already underway on Lanai through the Department of Energy.)

5. All necessary engineering, technical and financial studies and analyses to identify Big Wind project integration and performance requirements, undersea cable systems requirements, and Hawaiian Electric system modifications, infrastructure additions and operating solutions (“Implementation Studies”) will be conducted in a comprehensive but expedited manner. (See “Technology of Inter-Island Renewables” section.)

6. The developer of the selected Big Wind project is responsible for all matters related to the implementation of its wind farm facilities. These responsibilities include: (a) securing all land rights, permits and approvals (e.g. environmental, land use and construction) that are necessary for the efficient and effective development of its wind farm; (b) all related infrastructure and equipment that may be identified and required for the project pursuant to the Implementation Studies, and (c) any requirements, such as energy storage to meet performance standards, that may arise from a subsequent interconnection requirements study (“IRS”) conducted by Hawaiian Electric, and as embodied in a PPA between Hawaiian

Electric and the developers. The costs of fulfilling the aforementioned responsibilities shall be borne by the developer(s). Hawaiian Electric shall provide for appropriate additional storage capacity investments, grid upgrade additions, and grid operation management procedures to support the integration of the project with the overall grid.

7. Understanding the complexity of large scale infrastructure siting and investment in an Inter-Island Electric Cable, the State shall accept primary responsibility and shall serve as lead, while coordinating with developers, contractors, and/or Hawaiian Electric as the circumstances merit, on all matters related to the siting and permitting of the undersea cable systems consistent with the Implementation Studies. These responsibilities include but are not limited to conducting or having contractors and advisors conduct the appropriate engineering and design of the undersea cable systems, acquisition of all necessary off-shore and on-shore land rights, permits and approvals (including the Environmental Impact Statement), and construction, operation and maintenance of the undersea cable systems. The undersea cable systems shall be considered State owned infrastructure unless alternatives are discovered as part of the Implementation Studies and agreed to by relevant affected Parties. The State can also consider the option of bringing in a third-party independent transmission company to fund and build the inter-island cables.

Hawaiian Electric may enter into an agreement as a contractor with the State for the operation and maintenance of the undersea cable systems under such terms and conditions as the parties decide. Should Hawaiian Electric enter into any such operating and maintenance contract with the State, all reasonably incurred costs and expenses of Hawaiian Electric arising thereunder shall be recovered through the Clean Energy Infrastructure Surcharge (CEIS) mechanism.

8. The State shall first seek, with Hawaiian Electric’s and/or developer(s) reasonable assistance, federal grant or loan assistance to pay for the undersea cable systems. In the event that effort fails, the State will employ its best effort to fund the undersea cable systems through a prudent combination of taxpayer paid sources and ratepayer sources with acceptance that the cable system finance may have an effect on Hawaiian Electric and that a financially sound electric utility are vital components of our renewable energy future. In the event Hawaiian Electric funds any part of the cost to develop the undersea cable systems such that Hawaiian Electric has part ownership in the cable systems, all reasonably incurred capital cost and expense of Hawaiian Electric arising thereunder shall be recovered through the CEIS mechanism. However, nothing in this paragraph shall be construed as creating an obligation on Hawaiian Electric’s part to fund any part of the undersea cable systems costs.

9. The State and the selected wind farm developer shall work together, in consultation with Hawaiian Electric and other appropriate advisors and stakeholders as set forth in the conclusions of the Implementation Studies, to interconnect the undersea cable systems to the developer’s wind farm facilities located on Lanai or Molokai. Hawaiian Electric will be responsible for all required utility system connections or interfaces on Lanai or Molokai, if any, with the State’s undersea cable systems and/or the wind farm facilities. All necessary

Hawaiian Electric capital improvements will be proposed to the PUC for approval including its recovery supported by the State and the wind farm developer, and recovered, through the CEIS mechanism, until the next rate case, at which time such costs will be reflected in the test year rate base.

10. Hawaiian Electric is responsible for funding, constructing, operating and maintaining all land-based connections and infrastructure improvements to the existing Hawaiian Electric system up to the interconnection point located at the on-shore termination of the State owned undersea cable systems on Oahu. Hawaiian Electric will consult with, and seek agreement with the State on the selected route to the appropriate substation. The State will support, facilitate and expedite all required land use, environmental and regulatory permits and approvals associated with Hawaiian Electric’s land-based connections and infrastructure improvements. In the event Hawaiian Electric is unable after reasonable effort to secure the necessary permits and approvals or is delayed in its completion of the required land-based connections and infrastructure on Oahu, Hawaiian Electric is not responsible for the cost, expense, and any purported lost opportunity of the Big Wind project developer and the State related to their efforts toward the development of this renewable energy undertaking. All necessary Hawaiian Electric capital improvements will be proposed to the PUC, supported by the State and wind farm developer, and recovered through the CEIS mechanism, until the next rate case, at which time such costs will be reflected in the test year rate base.

11. In addition to the integration of Grandfathered Projects and possible projects resulting from the RE RFP, and the commitment to integrate up to 400 MW of wind power in Hawaiian Electric’s renewable energy commitments set forth in this agreement, an assessment will be conducted as a part of the Implementation Studies of the capability of the Oahu system to integrate additional wind energy from the neighbor islands in future years. Upon completion of the assessment and assuming it is possible, Hawaiian Electric agrees to integrate additional wind energy following the successful integration and commercial operation of the first large-scale wind farm. The Parties will review the process for the implementation of additional renewable energy and storage project opportunities from the neighbor islands and the Parties may agree to follow the same process identified in this section for the first neighbor island wind farm(s) to ensure that the proposal is in the best interest of the Parties and the ratepayers.

2 Renewable Energy Commitments

The parties are all committed to the rapid development of as much renewable energy as possible. To that end, the parties are looking to the development of a series of projects including, but not limited, to the listed projects.

Hawaiian Electric and the State commit to accelerate the addition of new clean energy resources on Oahu. To that end, the Parties recognize that Hawaiian Electric’s independent, ongoing efforts related to the Grandfathered Projects and the Oahu RE RFP currently in

progress may provide a reasonable near-term opportunity to add up to 235 MWs of new clean energy resources located on Oahu. Hawaiian Electric commits to continue independent negotiations for the purchase of renewable energy from the Grandfathered Projects and to efficiently complete the Oahu RE RFP. Should these projects prove feasible and demonstrate rate payer benefits as shown in information made available to the State and in the State’s sole opinion, the State commits to support, facilitate and help expedite these ongoing activities and processes, including the successful development of the resulting renewable energy projects.

It is understood that these projects must still be put before the Commission through PPA and that other new projects may come along as well. Hawaiian Electric will work to streamline PPA development for these projects in order to meet the commitment timeline set forth in Exhibit B of this agreement.

It is also understood that Hawaiian Electric’s move to biofuels is not intended to slow the implementation of these or other renewable energy projects.

It is understood that the Hawaiian Electric utilities will not add any new utility owned biofuel central-station generating units without equivalent retirements in terms of megawatthour energy generation of existing units. The utilities will not be allowed any cost recovery for any new utility biofuel generation units without the aforementioned equivalent retirement of existing units.

It is also understood that the Hawaiian Electric utilities shall not themselves add any new fossil-based generation over 2 MW beyond those already approved by the Commission or under construction without equivalent megawatthour retirements.

The parties do note that specific renewable energy projects may or may not result in power purchase agreements for reasons outside the control of the parties negotiating such agreements.

Hawaiian Electric will encourage and explore the development of the following project proposals known today, with the goal of bringing the maximum number of projects and renewable MW on-line as quickly as possible subject to Commission approval, contract negotiations, and grid integration feasibility.

Hawaiian Electric Company, Inc.

•

RFP (Competitive Bid for Non-firm Renewable Energy) (100 MW)

•

NorthShore Wind (30 MW) as-available with batteries for smoothing

•

Honua (6MW) Waste-to-Energy

•

C&C (21 MW) Waste-to-Energy

•

Sea Solar (25 MW to 100 MW) Ocean Thermal

•

Lockheed Martin (10 MW) Ocean Thermal

•

CIP CT-1 (110 MW) Biofuel Simple Cycle Gas Turbine

•

Airport DG (8 MW) Biofuel

•

DG at substations to Biofuel (30 MW)

•

Molokai or Lanai Wind (400 MW)

•

CIP CT-2 (100 MW) Biofuel

•

Military DG (100 MW) Mixed renewables

•

Waiau 3 and/or 4 Retirement (after CT-2 or Hawaiian Electric-Military DG on line)

•

RFP (Competitive Bid for Renewable Energy) Additional and Replacement Power (MW TBD)

Maui Electric Company, Ltd.

•

Shell Wind (21 MW) Wind

•

Lanai Solar (1.2 MW) Solar

•

Pulehu (6 MW) Biomass

•

Oceanlinx (2.7 MW) Wave

•

Landfill Gas (2 MW) Waste-to-Energy

•

KWPII (21 MW) Wind

•

HC&S extension Biomass

•

RFP (Competitive Bid for Firm Renewable Energy) Additional and Replacement Power (MW TBD)

Hawaii Electric Light Company, Inc.

•

Up to 40 MW of generation resources with full ancillary services, economic dispatch, energy payments only. Current possibilities are:

•

PGV Geothermal additional 8 MW

•

Hamakua Biomass (25 MW) or Hu Honua Biomass (22 MW)

•

Hi County Waste-to-Energy (4 MW)

•

Up to 5 MW of variable/intermittent generation resources with energy only payments. Current possibilities are:

•

SOPOGY (0.5 MW) Solar

•

Na Makani (4.5 MW) Wind with pumped hydro for “firming” and “smoothing”

If the above happens, HELCO’s fossil fuel generation will be displaced; depending upon how much of the above development occurs, the following may be possible:

•

Reduction in energy purchases from Hamakua Energy Partners

•

Reduction in energy production from HELCO fossil fuel units

•

Shipman (15 MW) Retired (after Biomass and PGV on line and bio-fueling not feasible)

•

Diesel-11 (2 MW) Retired

•

Puna Steam (15 MW) converted to Biomass

•

RFP (Competitive Bid for Firm and/or As-Available Renewables – due 2023) (MW TBD)

Energy storage, such as pumped storage hydro and battery energy storage as well as transmission and distribution facilities are considered as utility integrating technologies for generation resources. Energy storage and other technologies which provide ancillary services may be utility-owned or may be acquired with PPAs with appropriate prices, terms and conditions designed specifically for grid integration and ancillary services.

3 The Technology of Inter-Island Renewables

The Parties are all committed to the integration of non-fossil fuel, renewable energy, sourced first from the Renewables for Oahu Project(s). Over the long term, integration of renewable energy from neighbor islands may also occur should the results the Inter-Island Cable Study and additional Implementation Studies show that the resulting energy generation, delivery and grid integration costs provide true cost/benefit (in the face of imported oil and its associated price and supply risks) to the State and to Hawaiian Electric Companies’ ratepayers.

In conjunction with the analyses to integrate the Renewables for Oahu Project(s), the Parties agree to assess the potential of an expanded undersea cable system to Maui County and to facilitate additional, near term, balanced, renewable energy resources based on the study results, where such results and additional potential projects are found to be cost effective and prudently incorporated in the near term without interference with the Renewables for Oahu Project(s). The Parties understand that the economies of scale and the timing of capacity utilization of any proposed undersea cable configuration may materially affect the overall benefit to ratepayers and will work to facilitate utilization of the cable or renewable resources, while maintaining system reliability in accordance with the rest of this section.

The parties agree to utilize an experienced technical resource, such as the National Laboratories to independently validate and review the appropriateness of the scope and depth of analyses envisioned for the Implementation Studies below.

To successfully accomplish the objective of integrating renewable energy from the neighboring islands, minimize curtailment of as-available energy, and extract the most value of a Big Wind project, subject to confirmation in the independent validation above, the parties agree to work together on a set of Implementation Studies to identify:

The technical requirements of and configuration for the inter-island undersea cable systems to ensure their high availability in order to facilitate the transfer of all available energy from the wind farm.

The modifications and additions needed for existing Oahu and neighbor island AC transmission grids to reliably interconnect power from the inter-island high-voltage DC cables and transmit the wind farm energy to Oahu’s distribution system.

The energy storage or flexible generation (providing ancillary services and other attributes such as load following, frequency response, regulation, quick start, fast ramping, etc.) needed to offset the variable nature of the wind energy and to minimize the curtailment of wind or other intermittent energy projects.

The modifications needed on existing generating units (such as cycling conversion, etc.) to offset the variable nature of the wind energy and to minimize the “spilling” of wind.

The changes to operational practices and procedures needed to operate the island grids and integrate their operations with the wind farm.

The parties agree that the Oahu Implementation Studies will be based upon existing generation resources and transmission and distribution systems and will take into account projects identified in the Renewable Energy Commitments section above.

Using all available system, meteorological, and performance data of the island systems, the parties agree to conduct these Implementation Studies in a collaborative fashion to support a timely implementation of the neighbor island wind farm, the undersea cable systems, and the on-island transmission, generation, energy storage, and all other infrastructure necessary for the effective integration of the wind farm energy.

The parties agree that technical and operating requirements (including the design of the undersea cable systems, the modifications and additions to the Oahu transmission system, the amount of energy storage or flexible generation required, the kind of modifications needed to existing generating units, and the changes to operational practices) determined in the Implementation Studies should be based upon a robust infrastructure design that maintains reliability levels consistent with industry practices, customer expectations, and requirements of the PUC and strives to achieve a high fuel efficiency for the system.

The parties agree that these Implementation Studies involve the technical resources of the parties, and the technical assistance of leveraged resources such as the U.S. Department of Energy and its National Laboratories, the Hawaii Natural Energy Institute, and other appropriate technology advisors, both public and private, such as General Electric and other industry experts.

The parties agree to base the design and development of a neighbor island wind farm, the undersea cable systems, and the on-island transmission, generation, energy storage, and all

other infrastructure necessary for the effective integration of the wind farm, on the results of these Implementation Studies.

The parties agree to assess the ability of the Oahu, Maui, and Big Island grids to incorporate additional amounts of non-firm, variable renewable generation, such as significant amounts of distributed PV generation and a subsequent neighbor island wind farm.

The parties agree to analyze the expansion of the undersea cable system to the Island of Hawaii and to assess the potential of the expanded undersea cable to facilitate the development of additional renewable energy resources on the Island of Hawaii.

The intent of this effort is to identify the ability to utilize wind, solar, ocean, geothermal and other renewable resources to meet the electricity needs of the ratepayers of the Hawaiian Electric Companies. It is understood that actual build-out of the inter-island cables will probably happen in stages. Based on current knowledge the installation of the shallow cables from Maui County to Oahu are likely to happen first.

The parties agree that the cost of the Implementation Studies will be recovered through the CEIP surcharge.

The parties also agree to examine the impact that interconnection may have on revenue bond financing and to take appropriate follow up action. Appropriate follow up actions could include seeking changes to IRS regulations or the redemption of the revenue bonds and related capital structure costs.

4 The Solar Opportunity

Solar opportunities for Hawaii include solar water heating (SWH), photovoltaics (PV), and concentrated solar power (CSP).

The parties believe that solar energy represents an immediate and substantial renewable energy opportunity for Hawaii. In order to fully use that energy, the parties commit to the following:

1. A measure to address issues encompassed in the Governor’s June 26, 2008 press release on her signing of the mandatory solar roofing law enacted in 2008 will be submitted to the 2008- 2009 Legislative session, and will be supported by all parties.

2. The tax credits and rebates for the conversion of existing homes to solar water heating will be continued. The Hawaiian Electric Companies may bid to continue implementation of this program once responsibility for energy efficiency programs is transferred to the third-party administrator.

3. The Hawaiian Electric Companies will propose a full “pay as you save” style program under which the ratepayer (property owner or renter) requests solar water heating, the utility

provides the unit installed by a licensed solar dealer, and the unit is paid for through a “shared savings” approach using the ratepayer’s bill. The utility may outsource portions of the program administration. The utility will recover all prudently incurred costs related to this program. By the end of 2008, the Hawaiian Electric Companies will file an application with the PUC seeking approval to implement the program, with a goal of no less than 2,500 annual installations. Once the application is approved by the Commission, the Hawaiian Electric Companies shall be ready to implement the program. (This program is in addition to the ongoing solar water heating and pilot “pay as you save” programs that are currently authorized by the PUC.)

4. The Hawaiian Electric Utilities are responsible for expeditiously integrating customer-sited PV and CSP energy into the utility system via the Rule 14H tariff as modified in May, 2008. In addition, the Hawaiian Electric Companies shall incorporate the integration of PV systems in their Clean Energy Scenario Planning (“CESP”).

5. The Hawaiian Electric Companies agree to address and mitigate the system integration issues at the distribution and system level for PV technologies.

6. Support the installation of third-party and customer PV systems through feed-in tariffs that offer known, stable pricing terms and standardized interconnections (See Feed-in Tariff section).

7. Support customer energy payment options through modification of Hawaii’s Net Metering option to include provisions for the sale of excess energy produced by the customer’s net metered system on an annual basis and payment for such energy at the feed-in tariff rate or at a somewhat lower fixed rate to fairly balance the option risks available in all customer options. New net metered installations shall be required to incorporate time-of-use metering equipment and, when time-of-use rates are implemented on a full scale basis in Hawaii or the applicable area, the net metered customer shall move to time of use net metering and sale of excess energy. The Parties agree that net metering installations benefit from system ancillary services, but that the long term commodity risks accepted by installation owners and excess energy payments contemplated herein, adequately compensate for the use of ancillary services that are unique to small island systems.

8. In order to provide customers a third option, the Hawaiian Electric Companies shall facilitate the development of photovoltaic (PV) energy by submitting an application to the PUC for a “PV Host Program” by March 31, 2009 of this agreement being signed. This PV Host program will consist of the following elements:

a. Contracting to use a customer site, both commercial and residential, for the installation of a PV system. The site owner may be a part owner of the system. As consideration for providing a PV generation site, the site owner may receive a site rental payment and/or use a portion of the PV energy generated at their site.

b. The Hawaiian Electric Companies will competitively procure the installation of the systems, which can be owned by a third party and/or the utility.

c. In the case of third party-owned systems, the utility may purchase PV energy at a standard rate. That rate shall not be linked to avoided cost and is intended to provide long-term stable pricing. The initial rate shall be set based on a competitive solicitation done by the utility before the submission of the PV Host program application. The standard rate may be changed, subject to PUC approval, based on changes in tax laws and rebates, changes in PV system costs, and other developments in PV services.

d. The Hawaiian Electric Companies may purchase the PV system and add the system cost to the utility’s rate base, as long as the cost of the system is at or below the level established by the PUC.

e. The Hawaiian Electric Companies shall structure the program to acquire PV energy as efficiently as possible, with priority given to sites, which accommodate large amounts of PV. Attributes of these sites as well as relevant information from known candidate sites will be identified in the program design and in the PV Host program application that will be filed with the PUC.

f. Should federal legislation be altered so that the utilities may claim tax credits, the value of such tax credits shall be passed through to ratepayers in the form of lower rate based asset costs or other mechanism.

g. In these PV Host installations, the Hawaiian Electric Companies are responsible for integrating the energy into the utility’s system.

h. Such PV Host systems can be targeted toward customers, such as the Department of Education facilities and other State buildings and properties.

9. Once the program is approved by the Commission, the cost of acquiring PV energy, including but not limited to site rental payments, site improvements, interconnection, purchased energy, and PV Host program administration shall be paid for by all ratepayers. The estimated program costs and cost recovery mechanism will be provided in the program design and application that will be filed for Commission approval.

10. Hawaiian Electric will review utility property such as Kahe Valley for use as a PV and/or CSP site by March 31, 2009, and the results of such review will be shared with the State and the Commission. Hawaiian Electric will also present the process in by which development may be implemented at each site.

11. The Hawaiian Electric Companies agree to facilitate the development of CSP through PPA.

12. The Hawaiian Electric Companies agree to address and mitigate the system integration issues at the distribution and system level for PV and CSP technologies through the Rule 14H tariff, as amended in May 2008.

13. All utility PV systems and projects shall be subject to the same circuit limits as all non-utility customer sited DG resources.

5 Biofueling

The majority of electric power generated in Hawaii is produced through the burning of imported liquid fossil fuels. Significant activity is taking place both in Hawaii and around the world to produce biofuels, which can be substituted for liquid fossil fuels.

The use of sustainable, renewable biofuels in existing firm power units (utility and non-utility) will provide substantial levels of renewable energy, reduce greenhouse gas emissions, avoid the need to construct expensive replacement generation, and allow for the integration of intermittent resources such as wind and solar energy.

The demand created by the use of biofuels in Hawaiian Electric’s units will provide a strong basis for investment in the local biofuel industry, which, in turn, will bolster Hawaii’s agriculture sector and increase our energy independence and security, and retain dollars in the State.

In order to facilitate the use of biofuels in Hawaii, the parties commit and agree to the following:

1. The Hawaiian Electric utilities will affirm the technical feasibility of biofuel (and/or blends of biofuels with fossil fuels) use in their generating units via operational test burns beginning in 2009. Such testing will include:

a.	Procurement, transport, and storage of biofuels.

b.	Design, procurement, and installation of new equipment and instrumentation.

c.	State Department of Health approval of test burns. No individual test burn period shall be longer than three months, consistent with the Department of Health’s administrative rules.

2. The State will support, facilitate and expedite all permitting and approvals associated with the Hawaiian Electric utilities’ testing of biofuels in their generating units.

3. The State will provide the Hawaiian Electric utilities with maximum air permit flexibility during the test burns. If during testing, emissions approach permitted emission limits, the Hawaiian Electric utilities will terminate the tests. The Hawaiian Electric utilities may request temporary approval of higher emission limits to allow completion of the test burn. The State will facilitate and expedite the Department of Health’s approval of temporary emission limits. In no case shall a violation of State or federal ambient air quality standards be allowed to occur.

4. The Hawaiian Electric utilities will competitively procure sustainable biofuels to be used for the tests, and request expedited PUC approval of the test biofuel procurement contract(s) and the inclusion of the test biofuel, sustainability audit, tracing, and certification costs, and transportation, terminaling, throughput and related costs in the energy cost adjustment clause. The parties agree on the Hawaiian Electric utilities’ need to conduct biofuel tests and the appropriateness of including reasonable biofuel testing, audit, tracing, certification,

and transportation, terminaling, throughput and related costs in the energy cost adjustment clause or other appropriate surcharge mechanism that will allow for timely cost recovery. The parties agree to support utility recovery of all reasonable non-fuel related biofuel testing expenses that are not included in Hawaiian Electric’s existing base rates.

5. The results of the tests will be shared with the parties.

6. Subsequent to testing, implementation of long-term biofuel use in the Hawaiian Electric utilities’ power generating units may require air permit modifications and fuel infrastructure changes. The State and U.S. Department of Energy (DOE) will facilitate and expedite the State’s Department of Health’s and Federal Environmental Protection Agency’s approval of such permit modifications, and advocate for maximum regulatory discretion including possible exemption from New Source Review. Hawaiian Electric will be allowed full cost recovery for all prudent and reasonable fuel infrastructure changes deemed necessary to support the implementation of long-term biofuel use, upon commission review and approval.

7. Assuming technical feasibility and the ability to modify permits are confirmed, the Hawaiian Electric utilities will implement use of sustainable biofuels (and/or blends of biofuels with fossil fuels) in their generating units, subject to acceptable biofuel pricing and sufficient biofuel availability. The Hawaiian Electric utilities will maintain flexibility in their equipment and permits and will be allowed to use alternative fuels should significant biofuel supply or price disruptions occur.

8. Hawaiian Electric will convert generating units using liquid fossil fuels to using biofuels, to the extent reasonable and necessary to achieve RPS goals and to facilitate integration of other forms of renewable energy.

9. The Hawaiian Electric utilities will procure sustainably-produced biofuels in accordance with its NRDC environmental sourcing policy. The parties agree in principle that paying a reasonable cost premium to ensure sustainability is acceptable.

10. The Hawaiian Electric utilities will preferentially purchase biofuels that are locally grown and produced in Hawaii. The parties agree in principle that paying a reasonable cost premium for locally-produced biofuels is acceptable.

11. The State, via its State Biofuels Master Plan, will identify and implement financial incentives and land use and employment policies to encourage the development of a local biocrop and biofuel production industry.

12. The Hawaiian Electric utilities will consider and pursue options to actively incent or partner in local biofuel development projects either as a regulated utility or as an unregulated affiliate. The State agrees to support the utilities’ involvement in these projects subject to a showing of avoidance of conflicts of interest, and, if done as a regulated utility, reasonable ratepayer benefits.

13. The Hawaiian Electric utilities, as part of their ongoing research and development activity will provide financial support for research and development of locally-grown vegetable oils, research and development of algae and other next generation feedstocks, and local feedstock production and processing facilities. Currently, these activities are being conducted by the University of Hawaii and the Hawaii Agricultural Research Center.

14. The parties will support continued federal tax support for biofuels and will seek their extension to cover the full range of biofuel products including crude palm oil (CPO).

15. If there is a disruption of supply or delivery of biofuels or any technical or other similar biofuel related emergency situation, PUC approval must be sought by the utility before it can substitute fossil fuels for biofuels in operating new biofuel fired generating units beyond what is required for unit testing or startups/shutdowns.

6 Avoided Energy Cost Contracts

The parties regard avoided energy cost based on fossil fuel prices for renewable energy contracts as a vestige of the past. The Hawaiian Electric utilities will make a request of all existing independent power producers in which PPA are based on fossil fuel prices to renegotiate those contracts to delink their energy payment rates from oil costs and provide ratepayers with stable, long-term and predictably priced contracts. If such requests are not accepted, as opportunities arise, the Hawaiian Electric utilities will negotiate new contracts or extensions of existing contracts to delink their energy payment rates from oil costs. See Exhibit B for a list of existing PPA prices based on fossil fuel prices, and information on contract expiration dates.

All new renewable energy contracts are to be delinked from fossil fuel oil costs.

The utility will determine what ancillary services are needed to integrate proposed energy providers into the system and make appropriate investments to ensure grid reliability and performance. The utility will pay appropriate value for ancillary services provided by third parties.

7 Feed-in Tariffs

The parties agree that feed-in tariffs are beneficial for the development of renewable energy, as they provide predictability and certainty with respect to the future prices to be paid for renewable energy and how much of such energy the utility will acquire. The parties agree that feed-in tariffs should be designed to cover the renewable energy producer’s costs of energy production plus some reasonable profit, and that the benefits to Hawaii from using a feed-in tariff to accelerate renewable energy development (from lowering oil imports, increasing energy security, and increasing both jobs and tax base for the state), exceed the

potential incremental rents paid to the renewable providers in the short term. To that end, the parties agree to the following:

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The parties will respectfully request that by March, 2009, the Commission will conclude an investigative proceeding to determine the best design for feed-in tariffs that support the Hawaii Clean Energy Initiative, considering such factors as categories of renewables, size or locational limits for projects qualifying for the feed-in tariff, how to manage and identify project development milestones relative to the queue of projects wishing to take the feed-in tariff terms, what annual limits should apply to the amount of renewables allowed to take the feed-in tariff terms, what factors to incorporate into the prices set for feed-in tariff payments, and the terms, conditions, and duration of the feed-in tariff that shall be offered to all qualifying renewable projects, and the continuing role of the Competitive Bidding Framework;

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In addition, the parties will respectfully request that by July, 2009, the Commission will adopt a set of feed-in tariffs and prices that implement the conclusions of the feed-in tariff investigation;

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Utility PPA of renewable energy made using the Commission-approved feed-in tariff shall be deemed to be prudent and their costs shall be approved for rate recovery;

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Utility purchases of renewable energy under the feed-in tariff shall be counted toward the utility’s Renewable Portfolio Standard requirements;

The parties agree in principle that 10% of the utility’s energy purchases under feed-in tariff PPA will be included in the utility’s rate base through January 2015.

With the parties’ agreement to implement feed-in tariffs as a method for accelerating the acquisition of renewable energy and Hawaiian Electric’s implementation plan set forth in Exhibit B, towards the integration of the renewable energy commitments, the achievement of the utility renewable energy program goals, as well as the other commitments offered in this document as identified and summarized in Exhibit A, the parties further agree to request Commission suspension of the current intra-governmental wheeling docket (i.e., Docket No. 2007-0176) and the Schedule Q investigation (i.e., Docket No. 2008-0069) for a period of 12 months, with a goal of having parties review necessity of the docket.

8 Coal

The parties agree that new generators fueled, whole or in part, by coal are not in the best interests of the people of Hawaii. Any attempts to add new coal based generation in Hawaii will be opposed by the parties.

9 Renewable Portfolio Standard (RPS)

The parties agree that a Renewable Portfolio Standard is a desirable way to articulate and structure Hawaii’s electric utilities’ renewable energy acquisition obligations. To that end, the parties agree to the following:

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Energy savings from such technologies as energy efficiency, demand response, and renewable displacement shall not count toward the utilities’ RPS goals after 2014, but shall be fully counted with respect to achievement of the goals of the Hawaii Clean Energy Initiative.

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In addition to a 10% RPS goal in 2010, a 15% RPS goal in 2015, and a 25% RPS goal in 2020, Hawaii’s RPS goals shall be modified to require that 40% of the Hawaiian Electric utilities’ total RPS must be provided from renewable sources by 2030, and that through 2015 no more than 30% of the Hawaiian Electric utilities’ total RPS may come from imported biofuels consumed in utility-owned units.

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The Hawaiian Electric utilities will support the State and/or the PUC in incorporating these changes in the HRS §269-92, or in the exercise of the PUC authority. The parties understand that the PUC will impose penalties for non-compliance with the RPS.

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Electricity generation from refuse-derived fuels shall count toward the RPS because the energy produced by such generation is sustainable and avoids the social costs of landfill disposal.

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To the degree that liquid or solid fuels are burned in a mixture of renewable or sustainable and fossil fuels, only that portion which is renewable or sustainable (measured on a per BTU input basis) shall count toward the satisfaction of the RPS requirements.

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The Hawaiian Electric utilities may aggregate the renewable and sustainable generation and purchases across all islands in their service territory on a calendar year basis to meet their collective RPS requirements.

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All grid-connected renewable energy generation, both central-station and distributed, shall count towards the RPS goal.

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The RPS goals will be reevaluated every five years beginning in 2013 to determine whether they remain achievable, taking into account changes in technology, the status of the projects contemplated in this agreement, and necessary regulatory support. The reevaluation will also consider the status of biofuels and its ability to contribute to the RPS, as well as increase in sales for use in EV/PHEVs.

•

If any renewable energy generated or purchased by the Utility on DOD installations, and feeding power to the grid, cannot be considered in the calculation of the utility contribution to the RPS, the RPS goals will be adjusted accordingly.

10 Greening Transportation

For the Hawaii Clean Energy Initiative to reach its ambitious goal of 70 percent clean, renewable energy for electricity and transportation by 2030, a significant shift in the way we

travel around Hawaii, and especially Oahu, is essential. While the State needs to pursue a broad range of solutions for transportation, the parties agree to the following:

Addressing transportation issues will require a combination of solutions including:

1. Increased mass transit (more buses and some kind of fixed guide-way);

2. More fuel-efficient internal combustion vehicles;

3. Alternative fuels for vehicles;

4. Improved personal mobility (e.g., walking and bicycling); and

5. Behavioral changes (tele-commuting, car pool and van pool use, etc).

The most promising alternative fuel, by far, available today is electricity. Electrification of transportation can offer consumers a lower-cost alternative to gasoline. It also decreases greenhouse gas emissions from the transportation sector dramatically, while only slightly increasing emissions from the power sector.

A variety of electric vehicles are in various stages of use and development.

1. Present hybrids use only gasoline for fuel but run much of the time on electricity generated by the vehicle;

2. Plug-in hybrids will charge from the grid and run most of the time on electricity, seamlessly converting to small gasoline-powered internal combustion engines only as the battery charge runs out; and

3. “Pure” electric vehicles will run exclusively on electricity, either from direct recharging or a combination of recharging and battery swapping to extend their range.

Whatever combination of technologies ultimately succeeds, moving from gasoline-fired engines to electric engines makes sense now. Electric utilities have significant idle capacity overnight that could be used to re-charge vehicles (and swappable batteries) during off peak hours. Increasing off-peak loads also can allow greater use of renewable energy during these off-peak times.

The impact of pure EV/PHEVs upon the utility girds will be carefully studied, and PHEV adoption strategies will be designed to complement and leverage the utility grids and will note be pushed beyond the point where they become potentially harmful or costly to the electric grid or uneconomic on a pure BTU-in, transportation miles-out basis.

Therefore, it is agreed that the parties will make ‘greening’ of ground transportation in Hawaii a priority.

Under this agreement, the State will:

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Encourage adoption of ‘gas-optional’ electric vehicles (hybrids, PHEVs, and EVs) through a “tool box” of incentives, including but not limited to

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Tax credits and/or deductions;

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Preferential parking and HOV lane use;

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Waived or reduced registration/license fees;

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Incentives/rebates for multi-family buildings to wire or re-wire for electric vehicle charging;

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Preferred insurance rates;

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Incentives for rental car fleet conversion to “gas optional” vehicles; and

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Support for:

Dealer offerings (preferred financing, discounts, rebates);

Utility offerings (preferred rates, rebates, new meters);

Employer support (stipends, vehicle-sharing, parking); and

Web-based information center.

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Assist utilities in making necessary changes (described below) to adapt to a transportation electricity market, including installation of a smart grid and potentially modifying the existing time-of-use rates to establish a rate that encourages the recharging of batteries during the off peak periods, thereby enabling the utility to reduce the amount of renewable energy that may be curtailed during such periods, and supporting greenhouse gas measures, which consider the overall decreased greenhouse gas impacts of converting from gasoline-powered vehicles to cleaner gas-optional vehicles (i.e., not penalizing the utility for possible increased electricity generation to help achieve cleaner transportation objectives).

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For pure EVs, conduct a study to assess whether the additional charging stations and other custom infrastructure needs dictate that one specific EV program (e.g., A Better Place) must be chosen over others (this does not preclude also supporting hybrid EVs and PHEVs).

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Work with all parties to develop charging stations in high traffic areas.

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Lead by example and help develop the ‘gas optional’ vehicle market by becoming an early adopter of electric vehicles for its fleets.

Similarly, it is the responsibility of the electric utilities to:

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Lead by example and help develop the ‘gas optional’ vehicle market by becoming an early adopter of electric vehicles for its fleets.

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Speed installation of Advanced Metering Infrastructure including the meters and computerized control technology.

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Adopt time-of-use rates to encourage off-peak recharging and the computerized technology to monitor and control such recharging.

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Encourage adoption of renewable energy as the primary source of recharging power.

11 Displacement of Fossil Fuel Energy and “Retirements”

As a key part of the transition of the Hawaiian Electric Companies’ systems to a renewable energy future, the utilities will “retire” the older and less efficient fossil-fired firm capacity generating units by removing such units from normal daily operating service as expeditiously as possible. For purposes of this agreement retire means (1) to decommission and shutdown the unit; or (2) to place on “reserve standby status.”

The utility generating units affected, the relative timing of such change in operating status, and the association of such operating status with the implementation of other envisioned projects is described in the Renewable Energy Commitments section of this agreement.

Re-permitting older generation will take years, and cannot be done fast enough to meet an urgent need. At the same time, the ratepayers have made a substantial investment in these units. Being able to bring units out of reserve standby status is expected to save ratepayers millions of dollars, the utility years of time to obtain approval to operate the unit and can avoid sustained outages resulting from unforeseen events.

A generating unit placed on reserve standby status will retain its current operating permits to provide for energy supply to customers as called for by the utility based on system needs. These units will be placed in cold storage and cannot be placed on the utilities daily commitment schedule except under emergency circumstances. When the unit is brought out of standby status, the utility shall notify the Commission, the Consumer Advocate, the Federal Environmental Protection Agency (EPA), and the State Department of Health (DOH). The utility’s capital, operations and maintenance expenses related to placing and maintaining its units on standby status and to run the units under emergency conditions shall be subject to recovery through the rate process.

The utility with support of the parties will meet with the EPA and DOH to ensure that it is understood (1) that it is not intended that the reserve standby status is a permanent shutdown; (2) that the unit remains on State or federal emission inventories; (3) that the units will continue to be maintained; (4) that the unit can be brought back on line within six to eight weeks; and (5) that the unit’s status will be reexamined as part of the Clean Energy Scenario Planning process and its annual updates.

12 Energy Efficiency

It is the goal of all parties to ensure that Hawaii achieves the maximum possible levels of energy efficiency as it represents the most effective use of resources possible, including conservation by not using resources at all. To that end, the parties agree to the following:

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The parties will support the development of an Energy Efficiency Portfolio Standard (EEPS) for the State of Hawaii. The Hawaiian Electric utilities will support the State’s

effort in incorporating such EEPS in State statute, and will use its best efforts to achieve the energy efficiency goals established in the EEPS.

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By April 1, 2009, the Hawaiian Electric utilities will initiate a load research program to obtain detailed energy usage information about Hawaii energy customers’ electricity and gas appliance age and efficiency, energy use patterns, building energy use and efficiency characteristics, so this information can be used to develop energy efficiency and mass market renewables program designs and for future energy planning efforts.

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Beginning on April 1, 2009, the utilities will lead, in collaboration with the State and third-party administrator, new studies to determine the technical and economic potential for a broad variety of energy efficiency, demand response, and renewable substitution measures within Hawaii. The cost of such studies will be recovered through an appropriate surcharge mechanism.

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The third party administrator will take over the administration of all energy efficiency programs as ordered by the Commission. The parties believe that the utilities should be allowed to apply for and will support the utilities continued provision of energy efficiency programs to commercial and industrial customers, upon the administrator’s and Commission’s review and approval, for a three-year period while the third-party administrator gets established and defines the overall program direction;

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The third-party administrator, utilities and stakeholders (such as the IRP Advisory Group and C&I customers) will work together in a collaborative process to design effective, high-impact energy efficiency and renewable substitution programs that are expressed in five-year program plans.

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The State and utilities will work with the third-party administrator and stakeholders to identify and deliver a set of energy efficiency measures that are specifically targeted to benefit low income electric and gas users, and fund delivery of those measures through the Public Benefits Fund.

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By June 2009, the Commission, State and utilities will identify no fewer than six energy efficiency measures or sets of measures that can achieve high penetration and high savings impact quickly and cost-effectively, and develop a plan to begin delivering those measures to Hawaii electric customers beginning no later than September 2009. These programs can be funded by eliminating other efficiency programs that have been found to have less impact at higher cost, and will be implemented by the third-party administrator.

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The parties also agree that Hawaiian Electric may apply to implement the Residential New Construction (RNC) program, Residential Customer Energy Awareness (RCEA) program and the Residential Solar Water Heating (RSWH) program but that the State will not necessarily support their applications.

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The energy efficiency programs shall not provide incentives to encourage customers to switch to other fossil fuels.

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The parties agree to support the enactment of an energy efficiency portfolio standard at the 2009 session of the Legislature.

Upon approval of the programs by the Commission and the program responsibility is transferred to the third-party administrator, the utilities and the third-party administrator will

have budget flexibility to use the resources available to achieve the stated goals and energy use reduction targets and program goals within broad guidelines that permit the pursuit of market opportunities, but preserve the ability of customer segments to have equitable access to program participation.

13 Demand Response Programs

Demand Response programs, including load management programs, are a critical component of the reduction of electrical energy use. These programs allow specific customer loads to serve the interests of all ratepayers by allowing those loads to be controlled for grid reliability and cost management. In order to achieve the maximum potential of these programs, the parties agree to the following:

1. Administration of demand response should remain with the utilities because of the need to monitor electrical system status while deciding when and to what degree to invoke the demand reductions available through demand response programs.

2. The utilities should update direct load control programs to enable use of the programs as an emergency grid management option. MECO and HELCO will propose the implementation of new demand response programs and submit an application seeking Commission approval of such programs by June 30, 2009. Hawaiian Electric will determine the modifications deemed necessary to the existing direct load control programs currently authorized by the Commission. A well-designed demand response program is beneficial because the program enables the utility to maintain reliability during grid emergencies and defer generation additions.

3. The utilities will also explore the use of demand response as a mechanism to accommodate more renewable energy and to manage frequency fluctuations resulting from intermittent renewable resources connected to the grid and provide a recommendation for such use to the Commission by December 31, 2009, including a request for Commission approval for implementation.

4. Third-party demand response or load curtailment aggregators have demonstrated the ability to develop a variety of price-responsive event and responsive demand response options. Hawaiian Electric will work with these firms to insure the maximum use of this resource and propose an initial plan of action by June 30, 2009. In addition, Hawaiian Electric may conduct pilot projects with aggregators, which will provide an opportunity to demonstrate the value of their programs. Proposals seeking Commission approval for such pilot projects will be submitted by December 31, 2009.

5. Demand response pilots are a low risk approach to test new concepts, and test new communication technologies and hardware in island salt-spray environments separated by mountain ranges, valleys and ridges. Demand response pilots can also test software that will interface with existing customer information systems and test customer response to

demand response program designs and delivery. Thus, pilot programs may be an appropriate avenue to implement demand response in Hawaii. The Hawaiian Electric Companies will provide the Commission with an evaluation of the initial proposed pilot projects together with a proposed implementation date by December 31, 2009.

6. The Hawaiian Electric utilities will explore enabling technologies, and if appropriate, will add them to the system to make it easier for customers to receive energy pricing or event information and change or manage their energy use based on this new information. An assessment of such technologies will be incorporated into the Hawaiian Electric Companies’ Clean Energy Scenario Planning process.

7. The utilities will also allow demand response to provide a variety of ancillary services and encourage those demand-side ancillary services if they can be provided more precisely than supply-side resources. An assessment of the benefits of using demand response to provide ancillary services will be incorporated into the Hawaiian Electric Companies’ Clean Energy Scenario Planning process.

8. Program costs for existing and any new demand response programs shall be recovered through DSM surcharge.

14 Advanced Metering Infrastructure (AMI)

Advanced Metering Infrastructure is a critical component of a number of important aspects of the Clean Energy Initiative. The parties believe that AMI will help customers manage their energy use more effectively. To that end, the parties agree on the following:

1. Hawaiian Electric will apply to the Commission by November 30, 2008, for immediate approval to begin installing, on a first-come, first-served basis, advanced meters for all customers that request them. The application will also seek expedited approval to fully implement time-of-use rates on an interim basis for the customers requesting the installation of advanced meters. Unless the Commission identifies a compelling reason to do otherwise, all customers having advanced meters will be given the utility time-of-use or dynamic rate options and shall have to affirmatively opt out of the rate option.

2. The meters and associated costs will be paid for through the CEIS, until such costs are embedded and recovered in the utilities’ base rates in future rate cases.

3. By December 31, 2008, Hawaiian Electric will file a full application to install advanced meters to remaining customers and the communication and meter data management system, including the necessary software and appropriate pricing programs. The PUC application will identify the desired goals, business purposes, functionality and cost for advanced meters and the identification of a meter data management system with associated costs to purchase and install that will achieve the desired goals and purposes, including a

schedule for acquisition and installation of remaining meters and the customers to be served.

4. Upon Commission approval, AMI will be implemented as quickly as possible, along with proposals for time-of-use rates and customer electricity pricing information that facilitate substantive customer understanding and energy use management.

5. Hawaiian Electric will minimize the financial impacts on low income and disadvantaged customers who have limited options through a combination of tiered rates and lifeline rates.

6. The Hawaiian Electric utilities working with external experts will submit to the Commission an evaluation of the effectiveness of the utilities’ time-of-use rates and shall determine whether any changes are needed to the energy information communications and time-of-use rates to improve customers’ energy responsiveness. The utilities will complete this evaluation by December 31, 2009 and will submit a second report 1 year after the full deployment of AMI.

7. Beginning January 1, 2009, the utility will submit an annual report to the Commission on the number of customers currently served, number who opted out, customer load response, impact of time-of-use rates on customer’s monthly bills and feedback received from customers.

15 Pricing Principles and Programs

The pricing of electrical services can be used to motivate changes in customer electrical usage and allow customers who choose to take advantage of specific pricing programs to manage their electric bills. The parties agree that rates must recover the basic costs of utility service and further agree to the following:

The parties believe that rates should reflect the Bonbright principles, which promote fairness in cost allocation, promote efficient resource use, are practical to implement, easy to interpret, provide bill stability for the customers, avoid undue discrimination between customers, and provide adequate and stable revenues to Hawaiian Electric. Rates must reflect the basic cost of service.

The parties also believe that participation in pricing programs should generally be on an opt-out basis.

With those principles in mind, the parties agree that the Hawaiian Electric utilities will continue to convert the residential rates to inclining block rate structure to encourage energy conservation and efficient use of energy. The utilities will complete this conversion of the residential rates as part of the current rate cases before the Commission.

In the case of commercial and industrial customers, the current declining block rate structure will be replaced with mandatory time-of-use for all C&I customers. The utilities will

complete the implementation of mandatory time-of-use rates to commercial and industrial customers by class as AMI is implemented. Demand response options, parallel with AMI deployment, will be offered to all C&I customers. Hawaiian Electric will, on a continuing basis, evaluate the effectiveness of the program and customer response.

16 Meeting the Military’s Needs

The parties understand that the military services have specific objectives to improve energy efficiency in existing and new facilities, reduce dependence on fossil fuels, and improve military installation energy security while containing costs. The parties agree to support the military’s energy goals, and agree to allow the utilities to meet the military energy service needs through competitive or other service contracting methods as long as the utilities can provide such services in a way that benefits rather than compromises other ratepayers.

In order to meet the military service needs, various requests for proposals are being prepared that will seek specific technologies and resources through mechanisms such as Energy Savings Performance Contracts, Utility Energy Service Contracts, and Enhanced Use Leasing. Possible services the Utility could provide include Distributed or On Site Generation, Energy Efficiency Programs, Advanced Metering, Smart Grid technology, Load Control programs and Renewable Energy delivery.

Hawaiian Electric Company will actively participate in these processes and believes that retaining military service customers is in the best interests of all residents in the state of Hawaii. The State agrees to support the military processes and decisions.

17 Seawater Air Conditioning (SWAC)

Seawater Air Conditioning is an established energy displacement technology and is considered an important resource that all parties strongly support. Therefore the parties agree to support rebates for individual buildings or customers that choose SWAC and expedited SWAC permit review and approval by all State and County agencies, starting with the downtown Honolulu SWAC project.

All parties agree to support:

1.	Rebates that incent individual buildings to sign up for these projects;

2.	Adoption by individual customers in the affected areas;

3.	Expedited permit and approval review and action by all State and County agencies.

The parties support the initial project, the downtown Honolulu Seawater Air Conditioning (HSWAC) to be installed by 2010, with other projects to follow.

18 Distributed Generation (DG) and Distributed Energy Storage (DES)

Distributed generation, including biofueled and fossil facilities, combined heat and power, and small renewable technologies such as wind and photovoltaics, can help replace central station generation and improve local grid operations and reliability. Similarly, DES (such as batteries, ice storage systems, flywheels and super-capacitors) can aid in firming intermittent renewables and provide load shifting and peak-shaving capabilities. To support and accelerate the adoption of DG and DES (termed broadly, distributed energy resources), the parties agree to the following:

1. The Hawaiian Electric Companies will facilitate planning for distributed energy resources through the Clean Energy Scenario Planning process and Locational Value Maps, to identify areas where these resources have system benefits and can be reasonably accommodated. The Locational Value Maps will be completed and become publicly available by December 31, 2009.

2. The utilities will support non-utility DG and DES by improving the process and procedure for interconnecting non-utility DG and DES to make it faster, efficient, and more transparent. By June 30, 2009, the Hawaiian Electric utilities will submit a review of the implementation of the Rule14H tariffs, as amended in May, 2008.

3. All parties will support reconsideration of the Commission’s ban on utility-owned DG where it is proven that utility ownership and dispatch clearly benefits grid reliability and ratepayers’ interests, and the equipment is competitively procured.

4. If Hawaiian Electric owns any DG, it will power those units using sustainable biofuels or other renewable technologies and fuels.

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

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

7. The Hawaiian Electric Companies will support DES either customer-owned or utility-owned.

8. All parties will support Hawaiian Electric dispatchable standby generation (DSG) units upon showing reasonable ratepayer benefits.

9. In order to accept higher levels of DG on the utility grid, significant investment in smart grid technologies and changes in grid operations may be needed. These investments, if

demonstrated to be prudent and reasonable in cost, will be recovered through the Clean Energy Infrastructure Surcharge or through the general rate case recovery process.

19 Net Energy Metering (NEM)

The parties are in agreement that there should be no system-wide caps on net energy metering at any of the Hawaiian Electric utilities. Instead, the parties agree to the following:

•

Distributed generation interconnection will be limited on a per-circuit basis, where generation (including PV, micro wind, internal combustion engines, and net metered generation) feeding into the circuit shall be limited to no more than 15% of peak circuit demand for all distribution-level circuits of 12kV or lower;

•

New DG requests shall be processed and interconnected on a first-come, first-served basis unless the Commission specifies some other method;

•

For those circuits where interconnection requests (particularly for PV) approach the 15% limit, the utility will perform and complete within 60-days after receipt of an interconnection request, a circuit-specific analysis to determine whether the limit can be increased. For non inverter-based DGs, the analysis to determine whether the limit can be increased will be performed on a case-by-case basis based on the specifics of the DG project(s) proposed;

•

If the utility believes a specific DG installation poses a significant risk to circuit reliability and safety or grid stability, it will notify the applicant, the Consumer Advocate and the Commission, within 30 days from receipt of the completion of a circuit analysis and the identification of the need to defer the installation until further analysis can be conducted, and shall conduct that analysis within no more than three months from the date of the application request.

NEM currently provides an interim measure to encourage the installation of and pay for renewable energy generated from customer-sited systems, generally PV systems. The parties agree that NEM will be replaced with an appropriate feed-in tariff and new net metered installations shall be required to incorporate time-of-use metering equipment and, when time-of-use rates are implemented on a full scale basis in Hawaii or the applicable area, the net metered customer shall move to time of use net metering and sale of excess energy.

As part of the Clean Energy Scenario Planning (“CESP”) process, Locational Value Maps (“LVM”) identified in the CESP process can trigger an engineering review by the Hawaiian Electric Utilities to determine whether circuit limits can be safely raised above the threshold for the specific circuits in the LVM and if distribution circuit modifications can be made to increase the level of DG/NEM within the LVM.

Current provisions relating to interconnection requirements will remain in force.

20 Lifeline Rates

The Hawaiian Electric Companies and Consumer Advocate agree to explore by April 2009, the possibility of establishing “lifeline rates”, which are designed to provide a cap on rates for those who are unable to pay the full cost of electricity and submit a proposal for Commission approval by April 2009.

21 The Gas Company

The Hawaiian Electric Companies and The Gas Company are energy providers to a common group of customers and their collaboration can accelerate the success of the HCEI. Hawaiian Electric welcomes The Gas Company’s interest in producing renewable and sustainable fuels and will make every effort to use these renewable fuels in its existing and future power plants.

22 Green Contracting

Because select ratepayers of the utilities have renewable energy obligations or otherwise have a desire to obtain green attributes, and because renewable energy in Hawaii, unlike on the mainland, is cost competitive with and often cheaper than non renewable energy, the parties agree that green attributes should be separated from green energy pricing, and that the price benefits of green energy and the price stability to it provides, should be shared by all ratepayers. However, the best method to achieve this goal requires further evaluation, so the parties agree to help the Commission evaluate options for green contracting and RECs by May 2009 and recommend a preferred path forward to the Commission.

23 Resource Attributes: The Loading Order

The parties agree that the maximum possible use must be made of energy efficiency, demand response and renewable energy. The utilities shall apply this loading order in the CESP process in determining the utilities’ resource plans to supply the total system load.

24 Public Benefits Fund (“PBF”)

The parties agree that energy efficiency resources should be funded using a Public Benefit Fund. The parties agree to the following:

•

Respectfully request that the Commission establish a PBF that is funded by collecting 1% of each Hawaiian Electric utility’s total revenues in years one and two; 1.5% in years three and four; and 2% thereafter. Once sufficient load research and potential studies

allow more precise identification of the cost-effective and achievable levels of energy efficiency, the PBF collection amount will be based upon the desired level of such investments;

•

The Commission may adjust the PBF funding levels on a year-to-year basis. The monies shall be dedicated to the support of programs for the utility and ratepayers from whom the funds were collected, except for studies which can benefit the ratepayers of all of the Hawaiian Electric utilities;

•

Funds not spent in one year can be rolled over to another year and shall not be available to meet any current or past obligation of the State;

•

PBF monies will be spent for energy efficiency programs measures, incentives, market transformation, technical assistance, program administration, customer education, potential studies, and measurement and evaluation, as expended by the third-party administrator or program contractors, which may include the utilities;

•

PBF monies for incentives and subsidy payments shall be allocated among programs, measures, and customer groups at the discretion of the Commission with input from the utility, third-party administrator, and other stakeholders;

•

Criteria for fund allocation shall include program cost-effectiveness, likelihood of achieving high levels of energy savings and measure saturation, and equity between customer classes. Allocations and incentive levels that are set by the Commission should remain stable for a period necessary to allow for program certainty and continuity for utility customer and service providers. Adjustments based on market conditions and program evaluations are appropriate;

•

Program funding should remain stable long enough to create program certainty and continuity for program providers and utility customers;

•

At least 10% of each Hawaiian Electric utility’s PBF shall be spent on programs that serve low-income customers. The Commission has the discretion to adjust the amount after review of relevant potential studies and input from the utility and other stakeholders.

The Hawaiian Electric utilities shall encourage its customers whose bills are in arrears to take advantage of available energy efficiency programs and provide timely information and assistance on the programs available to them.

25 Investment in the Infrastructure

The parties agree in principle that maintaining the basic infrastructure of the current electrical system is a critical foundation to all other aspects of the Hawaii Clean Energy Initiative.

Furthermore, the parties also agree that it may be necessary to make additional investments in transmission, distribution, and generation to facilitate and integrate high levels of renewable energy production, and that those investments will be determined through the Clean Energy Scenario Planning process. The parties specifically reject deferred maintenance as an operating philosophy and commit to supporting reasonable and prudent investment in the ongoing maintenance and upgrade of the existing generation,

transmission, and distribution systems, unless the CESP process determines whether specific investments previously identified as being needed are subsequently rendered unnecessary through the implementation of effective energy efficiency, demand response, and distributed energy resources or non-utility generation.

26 The Smart Grid

The parties agree in principle that a “smart grid” is a critical component of Hawaii’s energy future. A smart grid builds upon existing utility generation, transmission and distribution, using automation, communications, analytics and controls to operate the grid more efficiently, reliably, and safely, and improve the integration and use of intermittent renewables, demand-side and decentralized resources. The parties agree to the following:

1. Increased levels of SCADA may be necessary for the Hawaiian Electric Companies’ distribution system. Evaluating and prioritizing which circuits to implement SCADA will include reviewing the levels of distributed generation by circuit and in total on each utility system, as well as the levels of monitoring, control systems, protection systems, and communications systems required to maintain system stability. The level of SCADA additions to the distribution system will be a significant consideration in evaluating system changes and upgrades required to maintain system reliability as each utility adds more renewable distributed generation to its system. Hawaiian Electric utilities will complete this evaluation and review of its circuits by December 31, 2009, and will submit a report of the results and recommendations to the Commission by such date.

2. As wind and solar systems are added to the grid, particularly at the distribution level, the utilities shall increase their real-time monitoring of the transmission and distribution system capability that includes monitoring of environmental factors such as wind speed, sunlight intensity and temperature.

3. In conjunction with an increased data collection capability as noted above, it may be necessary to install and implement forecasting and monitoring systems to better predict the wind and cloud patterns that affect variable renewable generation.

4. There is a need to develop an increased capability to remotely and automatically control transmission and distribution systems through the use of remote switching devices, voltage regulations devices, protective relaying, and individual distributed generation installations and individual loads.

5. In distribution circuits where DG penetration approaches levels which impact the effectiveness of static protective relaying, it may be necessary to upgrade the relay system to accommodate dynamic settings and higher penetration levels of distributed generation.

6. It may be necessary to implement distribution automation; transmission and distribution technologies and microgrids which address self-healing, resistance to attacks, power quality,

and accommodation of non-renewable generation. These technologies are intended to open new markets and increase grid efficiency and should be implemented if demonstrated to be cost effective.

7. Prudent and cost effective investment in smart grid technologies may be recovered through the Clean Energy Infrastructure Program or the general rate case process.

27 Transmission Planning

Transmission remains a key responsibility of the Hawaiian Electric Companies and a critical element of a clean energy future. To that end, the parties agree to the following:

1. The Hawaiian Electric Companies will perform and complete the planning analysis required to evaluate several scenarios under the Clean Energy Scenario Planning (CESP) process.

2. The CESP will identify new transmission projects for which the Hawaiian Electric Companies will then pursue PUC approval to proceed with the construction of the projects.

3. Transmission investments made to fulfill Clean Energy Scenario plans or renewable energy development zone commitments will, to the greatest extent possible, be supported by all parties including requests for the expeditious processing of the applications filed with the PUC.

4. Integration of generation (renewable, variable, or firm) is a complex process and the Hawaiian Electric Companies’ transmission and distribution planning analyses are necessary for evaluating generation interconnection proposals. The utilities will conduct the required evaluations within 6 months after receipt of a bona fide generation interconnection request. The utility may request additional information if it believes data received is incomplete or if additional data is required to complete an IRS, but cannot use a series of additional data requests to delay the process. The burden is on the utility to demonstrate that the additional data requests are necessary, or else the time to respond to data requests cannot be used to extend the 6-month deadline.

28 Decoupling from Sales

The transition to Hawaii’s clean energy future can be facilitated by modifying utility ratemaking with a decoupling mechanism that fits the unique characteristics of Hawaii’s service territory and cost structure, and removes the barriers for the utilities to pursue aggressive demand-response and load management programs, and customer-owned or third-party-owned renewable energy systems, and gives the utilities an opportunity to achieve fair rates of return. The parties agree in principle that it is appropriate to adopt a

decoupling mechanism that closely tracks the mechanisms in place for several California electric utilities, as follows:

1. The revenues of the utility will be fully decoupled from sales/revenues beginning with the interim decision in the 2009 Hawaiian Electric Company Rate Case (most likely in the summer of 2009).

The utility will use a revenue adjustment mechanism based on cost tracking indices such as those used by the California regulators for their larger utilities or its equivalent and not based on customer count. Such a decoupling mechanism would, on an ongoing basis, provide revenue adjustments for the differences between the amount determined in the last rate case and:

(a) The current cost of operating the utility that is deemed reasonable and approved by the PUC;

(b) Return on and return of ongoing capital investment (excluding those projects included in the Clean Energy Infrastructure Surcharge); and

Adjustments shall occur on a quarterly basis, semi-annual, or annual based or the availability of the indices utilized. The adjustments will continue until such time that they are incorporated in the utility’s base rates.

2. The parties agree that the decoupling mechanism that will be implemented will be subject to review and approval by the PUC.

3. The utility will continue to use tracking mechanisms for Commission-approved pension and other post-retirement benefits to ensure that the expenses are evened out for the ratepayer and are not subject to sudden and dramatic swing.

4. The Commission may review the decoupling mechanism at any time if it determines that the mechanism is not operating in the interests of the ratepayers.

5. The utility or the Consumer Advocate may also file a request to review the impact of the decoupling mechanism.

6. The Commission may unilaterally discontinue the decoupling mechanism if it finds that the public interest requires such action.

7. In order to implement the decoupling mechanism, the parties agree that HELCO and MECO will file for a 2009 test year rate case.

29 Clean Energy Infrastructure Surcharge (CEIS)

The Clean Energy Infrastructure Surcharge is designed to expedite cost recovery for infrastructure that supports greater use of renewable energy or grid efficiency within the utility systems. The parties agree to support the following:

1. The establishment of a CEIS to recover the reasonable costs of new transmission and other infrastructure investment needed to facilitate new clean energy investments by the utility or by IPPs. Subject to Commission approval, the CEIS may also be used to recover costs that would normally be expensed in the year incurred and may be used to accelerate cost recovery.

2. Capital costs eligible for recovery through the CEIS include the allowed return on investment based on the rate of return from the last rate case, AFUDC as appropriate, depreciation, applicable taxes, other costs as approved by the Commission.

3. The reasonable costs of infrastructure investments will be eligible for cost recovery through the CEIS if it can be demonstrated that the investments facilitate greater grid efficiency as determined and approved by the Commission, such as advanced meters and grid automation.

4. The reasonable costs of infrastructure investments that may be recovered through the CEIS, as determined by the Commission, include transmission lines built, in significant part, to facilitate renewable energy development, inter-connection equipment, advanced metering infrastructure, battery storage, and other equipment to facilitate increased use of renewable energy whether utility or third-party owned.

5. The CEIS may also be used to recover costs stranded by clean energy initiatives when approved by the Commission.

6. The CEIS is a mechanism to timely recover: (a) costs that would be expensed in the year incurred; and (b) a return on and of the costs of specific capital projects deemed necessary for the achievement of the HCEI objectives. The CEIS is not a financing vehicle for the Hawaiian Electric Companies.

7. If the utility is conducting a very costly capital investment project and receives Commission pre-approval for Construction Work in Progress (CWIP) rate base treatment, the utility can use the CEIS to recover the return on the CWIP asset. If the CWIP investment is given rate base treatment, it shall not earn AFUDC.

8. The CEIS will be implemented as a separate surcharge.

9. Cost recovery under the CEIS will terminate when and to the extent that the costs are incorporated in the utility’s base rates.

10. The CEIS surcharge will be reset on an annual basis to recover: (1) the capital and other related costs (as noted in paragraph 2 above) incurred by the utilities relating to the

adoption and integration of the renewable energy resources commitments identified in Exhibit A; (2) the change in the return on investment resulting from the change in the unrecovered cost of the projects completed in years prior to the immediately preceding year; and (3) the true up resulting from the reconciliation of the estimated and actual collections for the immediately preceding year. The new CEIS will take effect on March 1 of each year to allow for consideration of the Commission approved: (1) final costs of capital projects completed; (2) changes in the return on the net book value of the capital asset at the end of the immediately preceding year; (3) the results of the reconciliation to be performed by January 31 of each year of the estimated and actual costs to be recovered in the CEIS for the preceding year; and (4) any costs that should be expensed in the prior year, but are approved for recovery in the CEIS. The Hawaiian Electric utilities, the State, and the Consumer Advocate shall work in collaborative fashion in developing the implementation procedure of the CEIS recovery mechanism, for submission for PUC approval by November 30, 2008.

11. It is probable that it will be easier to achieve higher levels of renewable energy generation on islands other than Oahu. Subject to Commission approval, the CEIS may be used as a mechanism to have Oahu’s ratepayers pay for some of the cost burden of new renewable energy developments on the MECO and HELCO systems.

The utility has a Renewable Energy Infrastructure Program (REIP) pending at the Commission. The parties have no objection to the use of this docket after approval of the REIP to change the REIP to incorporate the CEIS mechanism changes, provided public notice is given to the ratepayers of the Hawaiian Electric Companies of the substitution changes and public hearings are held regarding the change, consistent with the requirements of HRS § 269-12.

30 Energy Cost Adjustment Clause (ECAC)

The parties agree that the goal of utility resource purchases is to maximize the purchase of renewable energy (and particularly locally-produced renewable energy), to de-link the renewable energy contracts from oil prices, and to stabilize, to the extent possible, ongoing fuel prices, in that order. To that end, the parties agree to the following:

•

The Hawaiian Electric Companies may engage in limited hedging and forward contracting for both energy and fuel using guidelines and practices to manage both cost and risk, as approved by the Commission;

•

The Commission will periodically review and approve the prudence and effectiveness of the Hawaiian Electric Companies’ utility’s fuel and energy procurement practices to ensure that the requirements of the energy cost adjustment clause are met. The Commission will examine whether there is renewable energy which the utility did not purchase or whether alternate purchase strategies were appropriately used or not used; and

•

The Hawaiian Electric Companies will be allowed to pass through reasonably incurred purchase power contract costs, including all capacity, O&M and other non-energy payments approved by the Commission (including those acquired under the feed-in tariff) through a separate surcharge.

•

If approved, these costs will be moved from base rates to the new surcharge.

•

The surcharge will be adjusted monthly and reconciled quarterly.

31 Preferred Stock / Hybrid Securities Offering

The utility must raise sufficient capital to fund the necessary infrastructure required for the Hawaii Clean Energy Initiative, and will do so in part by issuing a preferred stock/hybrid securities offering. Preferred stock/hybrid securities represent a less expensive form of financing than equity, but does not negatively impact the utility’s debt ratio as much as debt issuance would. The parties agree to support a reasonable preferred stock/hybrid securities offering proposal made by the Hawaiian Electric utilities to the Commission.

32 Clean Energy Scenario Planning (CESP)

To improve analysis and guidance for Hawaii’s clean energy future, the parties agree to replace the current Integrated Resource Planning (IRP) process with a new Clean Energy Scenario Planning (CESP) process. The parties agree to the following:

•

The CESP process will provide high level guidance on long term (10-20 years) direction and an Action Plan for near term initiatives (5 years), balancing how the utility will meet its customers’ expected energy needs as modified by planned energy efficiency, renewables substitution and demand response, encouraging high levels of renewable and clean energy with distributed resources, while protecting reliability at reasonable costs.

•

The CESP process will be conducted on an on-going basis with a new Clean Energy Scenario Plan developed in three-year cycles. The CESP process will include exploring alternative energy scenarios, risks and uncertainties, to develop a base case and variations for a 20-year planning horizon.

•

Since clean energy actions and choices on one island may affect the entire State, all Hawaiian Electric utilities shall conduct the CESP process in parallel or as one CESP process for all three utilities, using common economic and other assumptions and common scenarios for technology, economic, and development paths and options, while maintaining the option to also develop island-specific scenarios.

•

The Hawaiian Electric utilities shall conduct a comprehensive generation and transmission analysis every three years to support the evaluation of several planning scenarios to be considered in developing the new base case. In addition, the Hawaiian Electric utilities shall provide Locational Value Maps that will guide the identification of geographic areas of distribution system growth for potential application of new energy

efficiency, demand response, and distributed generation and storage within Clean Energy Investment Zones.

•

The CESP process will incorporate an Advisory Committee and a public review process;

Hawaiian Electric Company will complete and submit the Hawaiian Electric IRP-4 to the Public Utilities Commission by September 30, 2008. The Commission will receive the Hawaiian Electric IRP-4 and will be requested to close the docket and suspend HELCO’s and MECO’s IRP-4 dockets.

Hawaiian Electric Company shall request Commission approval to implement items in the Action Plan that otherwise require approval through the IRP-4 process.

The parties will request that the Commission open a new docket to establish the CESP process.

Pending the Decision and Order establishing the CESP process, each Hawaiian Electric utility will continue to meet with its Advisory Committees and file annual updates to its respective IRPs.

The parties agree that the specifics of the CESP Process, including the new CESP objectives and framework, are subject to Commission review and approval. Some of the specifics as may be proposed by the Hawaiian Electric utilities are described below.

33 Clean Energy Scenario Plan

Each utility will conduct a comprehensive generation and transmission analysis every three years to support the evaluation of several planning scenarios under consideration in the development of the new base case and will provide Locational Value Maps that will guide the identification of geographic areas of distribution system growth for potential new energy efficiency (EE), distributed response (DR), distributed generation (DG) and renewable substitution.

The Clean Energy Scenario Plan will take into consideration greenhouse gas emissions, impacts to local natural resources and to the local economy. The Clean Energy Scenario Plan will also identify, understand and characterize the risks and uncertainties that can make a significant difference to the utilities’ resource selection. As Hawaii transitions to greater integration of new renewable resources, it will increase the factors to manage the electric system, and the level of reliability may at times be impacted.

The Clean Energy Scenario Plan should define a manageable scope for the process, which includes annual updates (such as changes to the plan resulting from changes in sales and peak forecasts, fuel prices forecasts, new or changes in timing of generation resources, changes in penetration of DSM and other demand-side resources, etc.) to keep plans “fresh” with updated assumptions and to address/account for new issues (such as NEM limits). The

Clean Energy Scenario Plan must comply with requirements of the Competitive Bidding for New Generation Framework.

The Clean Energy Scenario Plan will include the following components subject to Commission review and approval:

a. Scenarios - The Clean Energy Scenario Plan should focus on higher level planning, such as scenario analyses and a preferred portfolio of energy sources/types, rather than identifying specific details on individual resources of the plan. These scenarios may feature different policy backdrops, such as major increases or decreases in oil prices, policy changes such as federal or international carbon regulation or the accelerated adoption of plug-in hybrid electric vehicles, as well as different resource policies that the PUC can influence or direct, such as higher levels of energy efficiency, demand response, and renewable substitution (e.g., solar water heating and seawater-cooled air conditioning). A reasonable number of Clean Energy Scenario Plan scenarios should be developed in consultation with the State, PUC and stakeholders to reflect a range of the possible energy-related policy choices and risks facing the State, its utilities and citizens.

b. Base case and variations - The Clean Energy Scenario Plan should start with a base case of the current IRP or Clean Energy Scenario Plan that incorporates current and forecast loads, demographics, economic conditions, fuel availability and prices, existing and planned resources (supply- and demand-side) and their capital and operating costs, and more other relevant information.

c. Analysis - The Clean Energy Scenario Plan should be supported by quantitative and qualitative tools to process data. Analysis tools may include production simulation models, load flow models, and resource screening models that employ, among several methods, probabilistic and Monte Carlo techniques to derive probability based results.

The Clean Energy Scenario Plan will use production simulation and resource screening models to identify the preferred energy contributions from various resources, taking into account the differing renewable energy impact, emissions, fossil fuel usage and cost into consideration. Existing contractual and forward looking operational requirements and constraints on the mix of generation types (such dispatch and curtailment requirements) will be factored into the analysis.

In addition to scenario analysis, technical analyses will need to be performed to determine the extent to which renewable resources with certain types of characteristics (e.g. intermittent, as-available resources, or fixed dispatch resources) can be integrated into the system while maintaining a stable and reliable electrical grid.

d. Scope - Clean Energy Scenario Plan includes an assessment of supply-side additions, supply-side retirements (or purchase power contract terminations) and demand-side resources as well as transmission requirements. Clean Energy Scenario Plan excludes an analysis of the distribution system, but should be coordinated with distribution planning to reflect the value and influence of distributed resources (energy efficiency, demand response,

renewable substitution and distributed generation) and to identify technical or operational issues that may arise if customer resources (especially customer-side distributed generation) develops into a high percentage of circuit or system demand.

e. CESP process Advisory Committee - At the start of the CESP process, the utility should form an advisory committee composed of key stakeholders (including the third-party energy efficiency program administrator), policymakers and customers to help the utility shape the scenarios and business cases, resource options, analysis, interpretation and public review processes.

f. Renewable Energy Zones (REZ) - REZ identification will be performed in coordination with the utility CESP process. The utility may request input from consultants and/or national agencies, such as NREL, who understand the potential areas of renewable energy development. With the support of these consultants, existing transmission facilities could be overlaid onto Geographic Information System (GIS) maps with the identified renewable resource locations.

g. System analysis - The utility should conduct a thorough, load flow transmission system analysis building on the base case assumptions and forecasts (including any known and measurable changes), evaluating grid conditions and flows for no less than a three-year period. That analysis, informed by relevant economic, load, and demand-side resource cases and scenarios, should be the basis for utility planning. The Clean Energy Scenario Plan would evaluate system level distributed generation and demand-side management (DSM) impact, taking into account the aggregate system impact to load and load flows on the transmission system to determine transmission and generation system benefits. Localized impacts to system loads will be taken into account in the transmission analysis as they are realized during the development of the base case model.

h. The CESP process identifies fossil needs - The CESP process will identify if new fossil fueled units are needed. These should be justified primarily by the need to balance and integrate variable renewable energy generation sources for overall grid reliability.

i. Locational Value Map - The utility will identify “geographic areas of distribution system growth” within the next 3-5 years where distributed resources and energy efficiency could be beneficial within the existing transmission and distribution system limits. The utility would identify “geographic areas” rather than individual circuits (i.e., today for Oahu, could identify the West side from Ocean Pointe to Ko ‘Olina; for the Big Island, various areas in West Hawaii and North Hawaii; for Maui, areas of Kihei and Lahaina) to maximize benefits and incorporate back up system needs. The information from the Locational Value Maps would be provided to parties such as the PBF Administrator so that EE DSM can be focused into geographic areas that would most benefit from energy efficiency. Determining value or price in the CESP process will be difficult because the potential to avoid distribution would depend on how much EE was being installed, the amount and type of renewable distributed generation being installed, and the planned operations of the DG resources.

j. Clean Energy Investment Zones - The utility should use the Locational Value Map to identify geographic areas where there is a high value to incremental investment in distributed generation, demand response, energy efficiency, or CHP. Such areas will be clearly delineated and termed “Clean Energy Investment Zones.” The utility will publicize the existence of these zones, focus efforts to sign up customers, and evaluate the need for an RFP for firm renewable distributed generation in the Clean Energy Investment Zones areas after considering factors such as the ability to meet renewable goals, cost effectiveness of renewable firm distributed generation, lack of proposals for renewable firm generation in the Clean Energy Zones or difficulty in attaining distribution assets within the needed time-frame. The utility will develop a streamlined procedure to help customers, third-party aggregators, and energy service companies contract with the utility to bring new clean energy resources into service in these Clean Energy Investment Zones. All of this information should be publicized in conjunction with the utility’s educational efforts following completion of the Clean Energy Scenario Plan.

k. Cost - The utility should purchase renewable energy at prices that are increasingly de-linked from oil prices. Avoided costs may be determined from the costs the utility would incur if it installed a renewable resource.

l. No-regrets resources - Upon completion of the Clean Energy Scenario Plan analyses, the utility should look for common themes, assets and strategies that demonstrate robust value to balance costs and risks across many of the scenarios and cases examined. These are likely to be “no-regrets” resources and strategies that will give the utility and State the greatest value and flexibility across a wide range of potential futures and uncertainties.

m. PUC Application for Transmission Assets - From the CESP process new transmission assets that require PUC approval will be identified. Hawaiian Electric will typically initiate more detailed studies in order to evaluate the appropriate asset to install. The detailed studies will be incorporated into the application for the new transmission asset that Hawaiian Electric submits for PUC approval. Transmission investments made to fulfill Commission-approved Clean Energy Scenario Plans or renewable energy development zone commitments shall require PUC approval pursuant to the requirements of the Commission’s administrative rules. Applications for approval submitted by the utility should receive expedited handling and the Hawaiian Electric Companies shall demonstrate the necessity of the project in application filed with the PUC. Upon Commission approval, the project costs may be recovered through either the CEIS or through a general rate case proceeding.

n. Public review – For the public review process of the Clean Energy Scenario Plan the Hawaiian Electric Companies shall provide information to policymakers, active stakeholders and the general public about future resource needs, opportunities and costs. The utility should seek feedback from citizens, consumers and policymakers in the State to assure that the Clean Energy Scenario Plan is reflecting the public interest. The process of review should be long enough to communicate effectively the information in the Clean Energy

Scenario Plan to the public audience, and to receive effectively public responses that can be integrated into subsequent planning work.

o. Regulatory review of the Clean Energy Scenario Plan - Regulators should review and evaluate the plan to see that it can accomplish its purposes and that it provides the strategic guidance for future utility planning decisions. This approval should elevate the status of the preferred resources identified in the Clean Energy Scenario Plan Action Plan to give them a presumption of need in any subsequent siting proceeding.

p. Timing of the CESP process - The utility will submit the new Clean Energy Scenario Plan to the Commission every three years, after a public review process. It is suggested that there should be an expedited time period for the Commission to complete its review and issue an order approving or denying the plan within six (6) months. If the Commission rejects all or parts of the CESP, there should be an explanation for non-approval and the implications of that non-approval on the utility’s asset investment and strategic choices for the upcoming three-year period. In order to continually reassess the CESP plan on a regular and timely basis, it is suggested that if the PUC has not issued a decision within a defined period, the plan is automatically deemed “approved.” The utility can continue public education about the Plan while it is under review at the Commission.

34 Federal Law and Rules

The energy picture in Hawaii is very different from the energy picture in other states. There are, however, certain Federal laws, which can either assist or hamper the Clean Energy Initiative.

The parties agree to support the following:

PURPA

•

Exempt Hawaii from PURPA

•

Adding an exemption that would cover Hawaii so that the utilities would be authorized to consider independent power producer (IPP) proposals under the State’s Competitive Bidding Framework when capacity or energy is needed rather than being compelled to consider purchase power proposals from qualifying IPPs as and when proposed, or to purchase power subject to all the terms and conditions in PURPA. RENEWABLES

•

Extend expiration of Biofuels Blender’s Tax Credit.

•

This tax credit will expire on December 31, 2008, before Hawaiian Electric’s CIP CT-1 is in service or MECO potentially purchases any biodiesel for its Maalaea units. The tax credit should reduce biodiesel costs for the utilities, and, thus, their ratepayers. The tax credit should also extend to all biofuels.

•

Expand PTC for Electric Generation from Biofuels

•

This credit is available for electric generation from biofuels, but only for units placed in service after 1992 and before 2006. That timeframe excludes Hawaiian Electric’s CIP CT-1 and several MECO Maalaea units.

ENVIRONMENTAL ISSUES

•

Include Volcano National Park volcanic air emissions in the background baseline for the Regional Haze Program.

•

EPA’s Regional Haze Rules, designed to protect visibility in National Parks, are ambiguous as to the effect of naturally occurring haze. Controlling visibility impairing emissions from Company units would be fruitless and very expensive.

•

Allow electrical generation units to switch to green fuels (biofuels) without triggering New Source Review (NSR).

•

Fuel switching could result in increased emissions (primarily NOx), potentially triggering NSR. Costs of NOx control on existing units switching to biofuels would be exorbitant with no appreciable benefit since we do not have a NOx problem in Hawaii.

35 Greenhouse Gas (GHG) Issues

Transforming the state’s energy dependence on oil to higher levels of efficiency and renewable energy will substantially reduce Hawaii’s Greenhouse Gas (GHG) emissions. Therefore, the parties agree:

•

All parties will support a policy for non-carbon or low carbon alternatives in future energy resource planning and selection (i.e. no coal);

•

The parties will support and select alternatives which help the State and utility meet the GHG requirements;

•

Guiding principles in GHG reduction measures include freedom of choice for energy consumers, a preference for incentives and market-based measures over regulatory penalties, and a balancing of the climate change mitigation burden fairly across all GHG emitters;

•

The parties will work collaboratively on State and federal GHG legislation to support the HCEI agreements and measures that take Hawaii’s unique conditions into account (e.g., HPOWER, potential federal exemptions, etc.);

•

Because of the uncertainties of GHG legislation at the State and federal level, the parties agree to suspend any decision to implement a State REC system until such time when these legislative actions become clear;

•

The State shall support and expedite approvals of necessary infrastructure and rate structures, including smart metering, which enable and accelerate measures designed to reduce GHG emissions;

•

As a goal during the renewal of power purchase contracts, the parties agree to move the Independent Power Producers to “green” alternatives and GHG compliance.

36 Telling the Energy Story

Public understanding of the Hawaii Clean Energy Initiative’s long-term energy security benefits for the State of Hawaii is critical for its success. Taking real action to achieve a clean energy future for our State requires commitment from all stakeholders – State government (including administration, legislature and regulators), utilities, other businesses (including transportation), communities, environmental groups and others. To that end, the parties agree to the following:

The State will take the lead in educating its citizens and businesses on the value of the Hawaii Clean Energy Initiative.

The State, with inputs from the utilities, and other stakeholders, will develop a common set of messages about the importance, rationale for and scope of the Hawaii Clean Energy Initiative. These may include:

•

As an island state, without interconnections to a mainland grid, developing clean local energy sources and fully embracing energy efficiency is critical to increase Hawaii’s energy security.

•

Many solutions for our islands will be different than elsewhere and must take into account the unique conditions of our small, remote, independent utility grids.

•

Reducing our dependence on imported oil must address both electricity and transportation.

•

Maintaining and upgrading the electric grid is essential to supporting reliable, renewable energy and to using technologies (such as advanced metering) that give customer options for better managing energy use.

•

Variable renewable sources — such as wind, solar, ocean and hydro — must be an important part of our energy mix. To reliably add large amounts of intermittent renewable energy sources to our small island grids, we need proper planning, new and developing technologies, a mix of fuel-flexible generation resources, and new operational practices.

•

Substantial investment will be necessary to develop local renewable energy fuel sources. Energy costs may be higher at first, but in the long run can be more stable than with current volatile oil pricing. In addition, future greenhouse gas or carbon taxes will increase the cost of fossil fuels even further.

These are investments in Hawaii’s future we must be willing to make. These are benefits, including energy security and protecting the environment, which we cannot put a price on. By ensuring energy security and protecting Hawaii’s special environment, we are creating a more responsible, cleaner future for our families, our communities and our islands. The utility and the State will work together to communicate these key messages to the public.

To maximize public awareness and understanding of this big picture, the communications campaign should utilize a full range of communication vehicles including utility advertising, free media and person-to-person communications with interested groups. Resources for such communications shall be authorized and recoverable.

37 How We Stay on Track

With the Hawaii Clean Energy Initiative, the State, the Consumer Advocate and Hawaiian Electric Company have reached a series of agreements that are critical to shaping Hawaii’s energy future. We are each committed to doing our respective parts to carry out our agreements. To that end, the parties agree that:

•

The State and utilities will identify a set of metrics that capture and quantify the important elements of the HCEI, and will set up a program to collect that information, calculate the metrics, and regularly report to citizens and stakeholders on the accomplishments of the HCEI relative to its goals;

•

The Hawaiian Electric utilities commit to integrate the renewable energy resources, and our responsibilities for achieving the target goals of the programs specified in the Hawaiian Electric’s Renewable Energy Commitments provided in Exhibit A;

•

The Hawaiian Electric utilities’ implementation plan and activities are detailed in Exhibit B. The Parties will meet quarterly and work collaboratively to ensure and monitor the performance and progress in achieving these commitments;

•

If one party feels another is not living up to their obligations, they will first raise that issue directly with the other party;

•

If there is a substantive breach of this agreement by a party(ies), the other party(ies) is not bound by any provisions that remain unexecuted of this agreement, and may change their position on any dockets already pending before the Commission; and

•

Any amendment or modification of this agreement shall not be valid unless it is in writing and signed by the parties. Any waiver hereunder shall not be valid unless it is written and signed by the party against whom waiver is asserted.

HECO TIMELINE

HAWAIIAN ELECTRIC COMPANY, INC. (HECO)


		Cumulative Target Goal (MW by year-end)
Renewable Energy Commitments		2010	2015	2020	2025	2030
RENEWABLE GENERATION
IPP Projects (info based on IPP proposals)
Kahuku Wind		30.0	30.0	30.0	30.0	30.0
Sea Solar OTEC			25.0	100.0	100.0	100.0
Lockheed Martin OTEC			10.0	10.0	10.0	10.0
Molokai and/or Lanai Wind			400.0	400.0	400.0	400.0
Honua Waste-to-Energy			6.0	6.0	6.0	6.0
C&C Waste-to-Energy			11.0	11.0	11.0	27.0
RFP Non-firm RE			100.0	100.0	100.0	100.0

Utility Projects
Airport DSG (Bio-fuel)		8.0	8.0	8.0	8.0	8.0
DG at substations (Bio-fuel)			30.0	30.0	30.0	30.0
CIP CT-1 (Bio-fuel)		110.0	110.0	110.0	110.0	110.0
CIP CT-2 (Bio-fuel)			110.0	110.0	110.0	110.0
Military DG (Biofuel)			50.0	62.5	75.0	75.0

Total RE Generation		148.0	890.0	977.5	990.0	1,006.0

ENERGY EFFICIENCY/CUSTOMER SITED GENERATION
PV (through feed-in tariff or PPA)		6.5	23.0	65.0	108.0	140.0
Solar Opportunity
Mandatory Solar Roofing, SB644		1.0	3.0	6.0	9.0	11.0
Pay-As-You-Save Solar Program		2.0	6.0	10.0	15.0	19.0
PV Host Program		2.0	12.0	22.0	32.0	42.0

Net Energy Metering		5.0	23.0	57.0	97.0	127.0

Distributed Generation & Distributed Energy Resources		0.0	8.0	15.5	23.0	35.0

Seawater Air Conditioning		0.0	16.0	16.0	16.0	16.0

Total EE/DG		16.5	91.0	191.5	300.0	390.0

TOTAL RE & EE/DG		168.5	1,015.0	1,220.0	1,358.0	1,481.0

PEAK REDUCTION/PEAK SHIFTING
Demand Response Program & Load Management		60.0	73.0	89.0	103.0	116.0

Pricing Programs
Residential TOU Rates	}
Commercial TOU Rates		2.0	10.0	20.0	31.0	41.0
Industrial TOU Rates
Critical Peak Pricing		2.0	24.0	31.0	37.0	44.0

TRANSPORTATION ELECTRIFICATION
Plug-In Hybrid Cars		600	36,000	66,000	96,000	126,000
(# of Cars, Oahu Only)

HELCO TIMELINES

HAWAII ELECTRIC LIGHT COMPANY, INC. (HELCO)


		Cumulative Target Goal (MW by year-end)
Renewable Energy Commitments		2010	2015	2020	2025	2030
RENEWABLE GENERATION
IPP Projects (info based on IPP proposals)
PGV Geothermal		8.0	8.0	8.0	30.0	30.0
Hamakua Biomass or Hu Honua			25.0	25.0	25.0	25.0
Hawaii County Waste-To-Energy			4.0	4.0	4.0	4.0
Sopogy Solar		0.5	0.5	0.5	0.5	0.5
Na Makani Wind and PSH			4.5	4.5	4.5	4.5

Total RE Generation		8.5	42.0	42.0	64.0	64.0

ENERGY EFFICIENCY/CUSTOMER SITED GENERATION
PV (through feed-in tariff or PPA)		1.8	7.8	18.0	30.0	39.0
Solar Opportunity
Mandatory Solar Roofing, SB644		1.0	4.0	8.0	12.0	15.0
Pay-As-You-Save Solar Program		0.2	1.0	3.0	4.0	5.0
PV Host Program		2.0	7.0	12.0	17.0	22.0

Net Energy Metering		1.3	6.0	14.0	24.0	32.0

Distributed Generation & Distributed Energy Resources		2.7	6.6	10.0	12.6	12.5

Total EE/DG		9.0	32.4	65.0	99.6	125.5

TOTAL RE & EE/DG		17.9	80.4	115.0	172.6	202.5

PEAK REDUCTION/PEAK SHIFTING
Demand Response Program & Load Management		0.0	1.0	4.0	4.0	4.0

Pricing Programs
Residential TOU Rates	}
Commercial TOU Rates		0.2	2.0	3.0	3.0	5.0
Industrial TOU Rates
Critical Peak Pricing		0.2	4.0	5.0	6.0	8.0

TRANSPORTATION ELECTRIFICATION
Plug-In Hybrid Cars		1,200	7,200	13,200	19,200	25,200
(# of Cars, Hawaii Only)

MECO TIMELINES

MAUI ELECTRIC COMPANY, LTD (MECO)


		Cumulative Target Goal (MW by year-end)
Renewable Energy Commitments		2010	2015	2020	2025	2030
RENEWABLE GENERATION
IPP Projects (info based on IPP proposals)
Shell Wind			21.0	21.0	21.0	21.0
Lanai Solar		1.2	1.2	1.2	1.2	1.2
Oceanlinx Wave			2.7	2.7	2.7	2.7
Pulehu Biomass			6.0	6.0	6.0	6.0
Landfill gas (Waste-to-Energy)		Unknown status.
KWP II			21.0	21.0	21.0	21.0

Total RE Generation		1.2	51.9	51.9	51.9	51.9

ENERGY EFFICIENCY/CUSTOMER SITED GENERATION
PV (through feed-in tariff or PPA)		1.8	7.8	18.0	30.0	39.0
Solar Opportunity
Mandatory Solar Roofing, SB644		1.0	3.0	6.0	9.0	11.0
Pay-As-You-Save Solar Program		0.1	2.0	3.0	5.0	6.0
PV Host Program		2.0	7.0	12.0	17.0	22.0

Net Energy Metering		2.2	10.0	24.0	42.0	54.0

Distributed Generation & Distributed Energy Resources		1.8	4.8	7.8	10.8	12.0

Total EE/DG		8.9	34.6	70.8	113.8	144.0

TOTAL RE & EE/DG		10.5	92.5	131.7	177.7	209.9

PEAK REDUCTION/PEAK SHIFTING
Demand Response Program & Load Management		4.0	8.0	9.0	10.0	10.0

Pricing Programs
Residential TOU Rates	}
Commercial TOU Rates		0.2	2.0	3.0	5.0	6.0
Industrial TOU Rates
Critical Peak Pricing		0.2	4.0	6.0	7.0	8.0

TRANSPORTATION ELECTRIFICATION
Plug-In Hybrid Cars		1,200	7,200	13,200	19,200	25,200
(# of Cars, Maui Only)

HECO TIMELINE

HAWAIIAN ELECTRIC COMPANY, INC. (HECO)

The following milestones are agreed upon by the parties. Any deviation from the milestones will need to be justified by the party and parties involved.

2008

2009

2010

2011

2012

2013

2014

2015

Item

ACTIVITIES & TASKS

RENEWABLE GENERATION - IPP Projects

Kahuku Wind

Complete term sheet

Perform IRS/Negotiate PPA

Commercial operation date (proposed by IPP)

Sea Solar OTEC

Complete term sheet

Perform IRS & PRS/Negotiate PPA

Commercial operation date (proposed by IPP)

Lockheed Martin OTEC

Awaiting proposal from IPP

Molokai and/or Lanai Wind

Bifurcate bids from RFP Non-firm RE

Implementation studies

Developers update proposals/pricing

Perform IRS/Negotiate PPA

Submit PPA for approval

Honua Waste-to-Energy

Complete term sheet

Perform IRS/Negotiate PPA

Commercial operation date (proposed by IPP)

C&C Waste-to-Energy

Request PUC Waiver from competitive bidding

Perform IRS/Negotiate PPA

Commercial operation date (proposed by IPP)

RFP Non-firm RE

Developers’ Proposals due

Select short list of bids

RENEWABLE GENERATION - Utility

Airport DSG (Biofuel)

Execute DSG Agreement

File DSG Agreement for PUC Approval

Commercial operation date

DG at substation (Biofuel)

Emission test

Engineering/Technical Evaluation

Permits and approvals

Conversion/Installation

CIP CT-1 (Biofuel)

Construction complete

Commercial operation date

CIP CT-2 (Biofuel)

Request for waiver to PUC

PUC application for project

Bio-fueling of Existing Units

Testing on K3

Biofuel testing study complete

Military DG

Prepare DG Proposal(s) (timing based on RFP)

Negotiate DG Agreements

Permitting and Approvals

Commercial operation date

ENERGY EFFICIENCY/CUSTOMER SITED GENERATION

Request opening of feed-in tariff docket

Mandatory Solar Roofing, SB644

Revisions to address SB644 issues

Pay-As-You-Save Solar Program

Application to expand program to 2,500 systems (statewide)

PV Host Program

Complete program design.

Submit Program application for PUC approval

Net Energy Metering

File stipulation with PUC to replace system cap with circuit cap

Energy Efficiency

1) Initiate energy usage study

2) Lead potential study for energy efficiency, demand response, and renewable substitution

3) PUC, State, utilities identify 6 energy efficiency measures

4) Deliver new measures

Distributed Generation &
Distributed Energy Resources

Review DG interconnection tariff Rule 14H, as modified May 2008, for transparency, efficiency, and opportunities for process improvement. Specify the interconnection study requirements for each general type of DG, the time required, and the utility process and time for mitigating grid issues.

Develop modifications, if necessary, to Rule 14H.

Develop and complete a Locational Value Map

Facilitate Development of Solar Generation

Complete review of utility properties such for use as PV and/or CSP sites

Seawater Air Conditioning

PUC approval of higher customer rebates completed

PEAK REDUCTION/PEAK SHIFTING

Demand Response Program

1) Implement HECO Residential Dynamic Prilcing Pilot program, filed April 2008, pending PUC approval

2) Customer portal (info feedback) proposal part of AMI system application

3) File HECO CIDLC and RDLC program renewals, including aggregator plan of action

4) File HECO CIDLC program aggregator pilot

5) File recommendations for demand response to address frequency fluctuations from intermittent RE

6) Evaluate Res DPP program, determine schedule to apply as option to all HECO residential, consider application to C&I customers as option

Residential TOU Rates

1) Implement residential inclined block rates in HELCO 2006, HECO 2007, and MECO 2007 rate cases, pending PUC approval

2) Implement aggressive residential TOU optional rates in HECO 2009 rate case, filed July 2008, pending PUC approval

3) File PHEV rate application, that encourages off peak vehicle charging, to coincide with commercialization of PHEVs.

Commercial TOU Rates

1) Apply existing optional TOU rates to C&I customers with AMI meters on opt-out basis (customers without AMI may opt-in to TOU)

2) Initiate COS study by TOU rate periods as basis for mandatory C&I TOU

3) Complete COS study and design mandatory C&I TOU rate

4) Eliminate load factor blocks and implement flat rates for all C&I customers in HECO’s 2009 rate case, filed July 2008, pending PUC approval

5) Mandatory TOU rates to apply to all C&I customers with demand charges when C&I AMI deployment is complete

DECOUPLING

Decouple utility revenues

HELCO TIMELINES

HAWAII ELECTRIC LIGHT COMPANY, INC. (HELCO)

The following milestones are agreed upon by the parties. Any deviation from the milestones will need to be justified by the party and parties involved.

2008

2009

2010

2011

2012

2013

2014

2015

Renewable Energy Commitments

ACTIVITIES & TASKS

RENEWABLE GENERATION - IPP
Projects

PGV Geothermal

Complete term sheet

Perform IRS/Negotiate PPA

Commercial operation date (proposed by IPP)

Hamakua Biomass or Hu Honua

Complete term sheet

Perform IRS/Negotiate PPA

Commercial operation date (proposed by IPP)

Hawaii County Waste-To-Energy

County council did not approve project.

Sopogy Solar

Perform IRS/Negotiate PPA

Commercial operation date (proposed by IPP)

Na Makani Wind and PSH

Complete term sheet

Perform IRS/Negotiate PPA

Commercial operation date (proposed by IPP)

Awaiting update by Na Makani Wind

Dec. 1, 2008. No update received.

ENERGY EFFICIENCY/CUSTOMER SITED GENERATION

Request opening of feed-in tariff docket

Mandatory Solar Roofing, SB644

Revisions to address SB644 issues

Pay-As-You-Save Solar Program

Application to expand program to 2,500 systems (statewide)

PV Host Program

Submit Program application for PUC approval

Net Energy Metering

File stipulation with PUC to replace system cap with circuit cap

Distributed Generation &
Distributed Energy Resources

Develop modifications, if necessary, to Rule 14H.

Develop and complete a Locational Value Map

Facilitate Development of
Solar Generation

Complete review of utility properties for use as PV and/or CSP sites

PEAK REDUCTION/PEAK SHIFTING

Demand Response Program &
Load Management

1) File HELCO load management programs with aggregator plan of action

2) File recommendations for demand response to address frequency fluctuations from intermittent RE

3) Evaluate Res DPP program, determine schedule to apply as option to all HELCO residential (contingent upon full scale installation of AMI meters and communication system. Consider application to C&I customers as option

Residential TOU Rates

1) Implement residential inclined block and TOU rates in HELCO 2006 rate case, pending PUC approval

2) Implement aggressive residential TOU optional rates in HELCO 2009 rate case

3) File PHEV rate application, that encourages off peak vehicle charging, to coincide with commercialization of PHEVs.

Commercial TOU Rates

1) Apply C&I TOU rates proposed in HELCO 2006 rate case on an interim basis to C&I customers selecting AMI meters, on opt-out basis (customers without AMI may opt-in to TOU)

2) Eliminate load factor blocks and implement flat rates for all C&I customers in HELCO’s 2009 rate case

3) Mandatory TOU rates to apply to all C&I customers with demand charges when C&I AMI deployment is complete

DECOUPLING

Decouple utility revenues, timing contingent on filing date of 2009 HELCO rate case

MECO TIMELINES

MAUI ELECTRIC COMPANY, LTD (MECO)

The following milestones are agreed upon by the parties. Any deviation from the milestones will need to be justified by the party and parties involved.

2008

2009

2010

2011

2012

2013

2014

2015

Renewable Energy Commitments

ACTIVITIES & TASKS

RENEWABLE GENERATION - IPP Projects

Shell Wind

Complete selection of performance standards

Perform IRS/Negotiate PPA

Commercial operation date (proposed by IPP)

Awaiting update by Shell Wind

Lanai Solar

Perform IRS/Negotiate PPA

Commercial operation date (proposed by IPP)

Oceanlinx Wave

Complete NUG form

Awaiting revised proposal form by Oceanlinx

Pulehu Biomass

Complete term sheet

Perform IRS/Negotiate PPA

Commercial operation date (proposed by IPP)

Awaiting update by Pulehu Biomass

Landfill gas (Waste-to-Energy)

Unknown Status

KWP II

Settlement Agreement

Perform Wind Integration Study

Perform IRS/Negotiate PPA

Commercial operation date (proposed by IPP)

ENERGY EFFICIENCY/CUSTOMER SITED GENERATION

Request opening of feed-in tariff docket

Mandatory Solar Roofing, SB644

Revisions to address SB644 issues

Pay-As-You-Save Solar Program

Application to expand program to 2,500 systems (statewide)

PV Host Program

Submit Program application for PUC approval

Net Energy Metering

File stipulation with PUC to replace system cap with circuit cap

Distributed Generation & Distributed Energy Resources

Develop modifications, if necessary, to Rule 14H.

Develop and complete a Locational Value Map

Facilitate Development of Solar Generation

Complete review of utility properties for use as PV and/or CSP sites

PEAK REDUCTION/PEAK SHIFTING

Demand Response Program & Load Management

1) File MECO load management programs with aggregator plan of action

2) File recommendations for demand response to address frequency fluctuations from intermittent RE

3) Evaluate Res DPP program, determine schedule to apply as option to all MECO residential (contingent upon full scale installation of AMI meters and communication system. Consider application to C&I customers as option

Residential TOU Rates

1) Implement residential inclined block rates in MECO 2007 rate case, pending PUC approval

2) Implement aggressive residential TOU optional rates in MECO 2009 rate case

3) File PHEV rate application, that encourages off peak vehicle charging, to coincide with commercialization of PHEVs.

Commercial TOU Rates

1) Apply C&I TOU rates proposed in MECO 2007 rate case on an interim basis to C&I customers selecting AMI meters on opt-out basis (customers without AMI may opt-in to TOU)

2) Eliminate load factor blocks and implement flat rates for all C&I customers in MECO’s 2009 rate case

3) Mandatory TOU rates to apply to all C&I customers with demand charges when C&I AMI deployment is complete

DECOUPLING

Decouple utility revenues, timing contingent on filing date of 2009 MECO rate case

Existing renewable IPP contracts with energy charge tied to oil prices



Name	Prime Mover [Primary Fuel]	Contract Effective Term [Term Years]
Hawaiian Electric Company, Inc.
H-POWER	Steam Turbine [Mun Waste]	Mar 31, 1986 (Jun 30, 1992 for FCA) to Jul 31, 2015 or at least 52 months’ advance notice to terminate [25]
Hawaii Electric Light Company, Inc.
Puna Geothermal Ventures	Geothermal Turbine (ten 3 MW) [Geothermal]	Mar 25, 1986 (Feb 14, 1990 for FCA) to at least Dec 31, 2027 [minimum 35]
Hawi Renewable Development, Inc. [HRD]	Wind Turbine [Wind] (sixteen .660 MW)	May 19, 2006 to at least May 18, 2021 (minimum 15)
Tawhiri Power LLC (wholly owned subsidiary of Apollo Energy Corporation)	Wind Turbine (fourteen 1.5 MW: Group A (8,6,4,1,3)—7.5 MW; Group B (13,12,7,5,2, 14,11,10,9)—13.5 MW) [Wind]	Apr 3, 2007 to at least Apr 2, 2027 [minimum 20]
Wailuku River Hydroelectric Limited Partnership	Hydro Turbine (two 5 MW) [Water]	Mar 6, 1991 to May 12, 2023 [30]
Maui Electric Company, Ltd.
Hawaiian Commercial & Sugar [HC&S] (a division of Alexander and Baldwin)	Steam Turbine 5 steam (TG3 10, TG4 18, TG5 16, TG1 10, TG2 2) and 3 hydro (Kaheka 4.5, Paia 0.9, Hamakua 0.6) [Bagasse]	Nov 30, 1990 to at least Dec 31, 2014
Kaheawa Wind Power, LLC — Owner; UPC Wind Management, LLC — Operator; Kaheawa Wind Farm — Facility	Wind Turbine (twenty 1.5 MW) [Wind]	Jun 9, 2006 to at least Jun 8, 2026 [minimum 20]
Makila Hydro, LLC	Hydro Turbine [Water]	Sep 22, 2006 to at least Sep 21, 2026 [minimum 20]

Note:

Utility’s filed short-term avoided energy cost and filed Schedule Q rate are tied to fossil fuel prices.

HECO Exhibit 12.2

Hawaiian Electric Company, Inc. and Subsidiaries

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

(unaudited)


	Nine months ended September 30						Years ended December 31
	2008			2007			2007			2006			2005			2004			2003
	(dollars in thousands)
Fixed charges
Total interest charges	$	40,712		$	40,267		$	53,268		$	52,563		$	49,408		$	49,588		$	44,341
Interest component of rentals		1,729			1,626			2,250			1,863			1,311			909			820
Pretax preferred stock dividend requirements of subsidiaries		1,093			1,037			1,438			1,467			1,461			1,459			1,430
Preferred securities distributions of trust Subsidiaries		—			—			—			—			—			—			7,675

Total fixed charges	$	43,534		$	42,930		$	56,956		$	55,893		$	52,180		$	51,956		$	54,266

Earnings
Income before preferred stock dividends of HECO	$	78,759		$	24,788		$	53,236		$	76,027		$	73,882		$	82,257		$	79,991
Fixed charges, as shown		43,534			42,930			56,956			55,893			52,180			51,956			54,266
Income taxes (benefit) (see note below)		47,065			13,016			30,937			46,440			44,623			49,479			49,824
Allowance for borrowed funds used during construction		(2,564	)		(1,840	)		(2,552	)		(2,879	)		(2,020	)		(2,542	)		(1,914	)

Earnings available for fixed charges	$	166,794		$	78,894		$	138,577		$	175,481		$	168,665		$	181,150		$	182,167

Ratio of earnings to fixed charges		3.83			1.84			2.43			3.14			3.23			3.49			3.36


Note:
Income taxes (benefit) is comprised of the following:
Income tax expense relating to operating income from regulated activities	$	47,507		$	15,974		$	34,126		$	47,381		$	45,029		$	50,059		$	50,175
Income tax benefits relating to results from nonregulated activities		(442	)		(2,958	)		(3,189	)		(941	)		(406	)		(580	)		(351	)

	$	47,065		$	13,016		$	30,937		$	46,440		$	44,623		$	49,479		$	49,824

For purposes of calculating the ratio of earnings to fixed charges, “earnings” represent the sum of (i) pretax income before preferred stock dividends of HECO and before adjustment for undistributed income or loss from equity investees and (ii) fixed charges (as hereinafter defined, but excluding the allowance for borrowed funds used during construction). “Fixed charges” represent the sum of (i) interest, whether capitalized or expensed, (ii) amortization of debt expense and discount or premium related to any indebtedness, whether capitalized or expensed, (iii) the estimate of the interest within rental expense, (iv) the preferred stock dividend requirements of HELCO and MECO, increased to an amount representing the pretax earnings required to cover such dividend requirements, and (v) in 2003 and prior years when the trust subsidiaries were consolidated, the preferred securities distribution requirements of the trust subsidiaries.

HECO Exhibit 31.3

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

I, Constance H. Lau, certify that:

1.	I have reviewed this report on Form 10-Q for the quarter ended September 30, 2008 of Hawaiian Electric Company, Inc. (“registrant”);

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(a)

(b)

(c)

(d)

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 4, 2008

/s/ Constance H. Lau

Constance H. Lau

Chairman of the Board

HECO Exhibit 31.4

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

I, Tayne S. Y. Sekimura, certify that:

1.	I have reviewed this report on Form 10-Q for the quarter ended September 30, 2008 of Hawaiian Electric Company, Inc. (“registrant”);

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(a)

(b)

(c)

(d)

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 4, 2008

/s/ Tayne S. Y. Sekimura

Tayne S. Y. Sekimura

Senior Vice President, Finance and Administration

HECO Exhibit 32.3

Hawaiian Electric Company, Inc.

Written Statement of Principal Executive Officer Furnished Pursuant to

18 U.S.C. Section 1350,

as Adopted by

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of Hawaiian Electric Company, Inc. (HECO) on Form 10-Q for the quarter ended September 30, 2008 as filed with the Securities and Exchange Commission (the HECO Report), I, Constance H. Lau, Principal Executive Officer of HECO, certify, pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1)	The HECO Report fully complies with the requirements of section 13(a) of the Securities Exchange Act of 1934; and

(2)	The HECO consolidated information contained in the HECO Report fairly presents, in all material respects, the financial condition as of September 30, 2008 and results of operations for the three and nine months ended September 30, 2008 of HECO and its subsidiaries.

/s/ Constance H. Lau

Constance H. Lau

Chairman of the Board

Date: November 4, 2008

A signed original of this written statement required by Section 906 has been provided to HECO and will be retained by HECO and furnished to the Securities and Exchange Commission or its staff upon request.

HECO Exhibit 32.4

Hawaiian Electric Company, Inc.

Written Statement of Chief Financial Officer Furnished Pursuant to

18 U.S.C. Section 1350,

as Adopted by

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of Hawaiian Electric Company, Inc. (HECO) on Form 10-Q for the quarter ended September 30, 2008 as filed with the Securities and Exchange Commission (the HECO Report), I, Tayne S. Y. Sekimura, Chief Financial Officer of HECO, certify, pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1)	The HECO Report fully complies with the requirements of section 13(a) of the Securities Exchange Act of 1934; and

(2)	The HECO consolidated information contained in the HECO Report fairly presents, in all material respects, the financial condition as of September 30, 2008 and results of operations for the three and nine months ended September 30, 2008 of HECO and its subsidiaries.

/s/ Tayne S. Y. Sekimura

Tayne S. Y. Sekimura

Senior Vice President, Finance and Administration

Date: November 4, 2008