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

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 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): Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨ (Do not check if a smaller reporting company) Smaller reporting company ¨

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): Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer x (Do not check if a smaller reporting company) Smaller reporting company ¨

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

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

APPLICABLE ONLY TO CORPORATE ISSUERS:

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


Class of Common Stock		Outstanding April 30, 2008
Hawaiian Electric Industries, Inc. (Without Par Value)		84,077,675 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 March 31, 2008

INDEX


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

PART I. FINANCIAL INFORMATION

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

	Hawaiian Electric Company, Inc. and Subsidiaries
	Consolidated Statements of Income (unaudited) - three months ended March 31, 2008 and 2007	15
	Consolidated Balance Sheets (unaudited) - March 31, 2008 and December 31, 2007	16
	Consolidated Statements of Changes in Stockholder’s Equity (unaudited) - three months ended March 31, 2008 and 2007	17
	Consolidated Statements of Cash Flows (unaudited) - three months ended March 31, 2008 and 2007	18
	Notes to Consolidated Financial Statements (unaudited)	19
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
	HEI Consolidated	36
	Electric Utilities	41
	Bank	62
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	65
Item 4.	Controls and Procedures	67

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	68
Item 1A.	Risk Factors	68
Item 5.	Other Information	68
Item 6.	Exhibits	69
Signatures		70

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended March 31, 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.). AdCommunications, Inc. (dissolved in May 2007) is a former subsidiary.
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 HEIPC (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
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
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
HECO		Hawaiian Electric Company, Inc., an electric utility subsidiary of Hawaiian Electric Industries, Inc. and parent company of Hawaii Electric Light Company, Inc., Maui Electric Company, Limited, HECO Capital Trust III (unconsolidated subsidiary), Renewable Hawaii, Inc. and Uluwehiokama Biofuels Corp.

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 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 subsidiary of HEI Power Corp.
HEIRSP		Hawaiian Electric Industries Retirement Savings Plan
HELCO		Hawaii Electric Light Company, Inc., an electric utility subsidiary of Hawaiian Electric Company, Inc.
HPOWER		City and County of Honolulu with respect to a power purchase agreement for a refuse-fired plant
HREA		Hawaii Renewable Energy Alliance
IPP		Independent power producer
IRP		Integrated resource plan
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
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
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)) and decisions concerning the extent of the presence of the federal government and military in Hawaii;

•

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 financing;

•

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);

•

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 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, 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 new accounting principles (such as the effects of Statement of Financial Accounting Standards (SFAS) No. 158 regarding employers’ accounting for defined benefit pension and other postretirement plans and Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 48 regarding uncertainty in income taxes), continued regulatory accounting under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” and the possible effects of applying FIN 46R, “Consolidation of Variable Interest Entities,” and Emerging Issues Task Force 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; and

•

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

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

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)


Three months ended March 31	2008			2007
(in thousands, except per share amounts and ratio of earnings to fixed charges)
Revenues
Electric utility	$	623,889		$	447,678
Bank		105,844			104,460
Other		(116	)		1,885

		729,617			554,023

Expenses
Electric utility		572,906			434,686
Bank		82,481			86,032
Other		3,484			4,764

		658,871			525,482

Operating income (loss)
Electric utility		50,983			12,992
Bank		23,363			18,428
Other		(3,600	)		(2,879	)

		70,746			28,541

Interest expense—other than on deposit liabilities and other bank borrowings		(19,249	)		(20,511	)
Allowance for borrowed funds used during construction		762			598
Preferred stock dividends of subsidiaries		(473	)		(473	)
Allowance for equity funds used during construction		1,901			1,232

Income before income taxes		53,687			9,387
Income taxes		19,720			2,623

Net income	$	33,967		$	6,764

Basic earnings per common share	$	0.41		$	0.08

Diluted earnings per common share	$	0.41		$	0.08

Dividends per common share	$	0.31		$	0.31

Weighted-average number of common shares outstanding		83,472			81,448
Dilutive effect of stock-based compensation		142			265

Adjusted weighted-average shares		83,614			81,713

Ratio of earnings to fixed charges (SEC method)
Excluding interest on ASB deposits		2.31			1.22

Including interest on ASB deposits		1.90			1.14

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

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)


(dollars in thousands)	March 31, 2008			December 31, 2007
Assets
Cash and equivalents	$	189,959		$	145,855
Federal funds sold		17,184			64,000
Accounts receivable and unbilled revenues, net		298,304			294,447
Available-for-sale investment and mortgage-related securities		2,086,037			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		4,153,950			4,101,193
Property, plant and equipment, net of accumulated depreciation of $1,775,790 and $1,749,386		2,761,396			2,743,410
Regulatory assets		283,498			284,990
Other		351,408			338,405
Goodwill, net		83,080			83,080

	$	10,322,580		$	10,293,916

Liabilities and stockholders’ equity
Liabilities
Accounts payable	$	213,966		$	202,299
Deposit liabilities		4,330,356			4,347,260
Short-term borrowings—other than bank		199,281			91,780
Other bank borrowings		1,789,157			1,810,669
Long-term debt, net—other than bank		1,202,028			1,242,099
Deferred income taxes		154,988			155,337
Regulatory liabilities		268,890			261,606
Contributions in aid of construction		300,847			299,737
Other		524,764			573,409

		8,984,277			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: 83,956,023 shares and 83,431,513 shares		1,084,267			1,072,101
Retained earnings		233,213			225,168
Accumulated other comprehensive loss, net of tax benefits		(13,470	)		(21,842	)

		1,304,010			1,275,427

	$	10,322,580		$	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)


	Common stock			Retained earnings			Accumulated other comprehensive
(in thousands, except per share amounts)	Shares	Amount		Retained earnings			loss			Total
Balance, December 31, 2007	83,432	$	1,072,101	$	225,168		$	(21,842	)	$	1,275,427
Comprehensive income:
Net income	—		—		33,967			—			33,967
Net unrealized gains on securities
Net unrealized gains on securities arising during the period, net of taxes of $5,808	—		—		—			8,796			8,796
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $372	—		—		—			(563	)		(563	)
Retirement benefit plans:
Amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes of $923	—		—		—			1,448			1,448
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $834	—		—		—			(1,309	)		(1,309	)

Comprehensive income	—		—		33,967			8,372			42,339

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

Balance, March 31, 2008	83,956	$	1,084,267	$	233,213		$	(13,470	)	$	1,304,010

Balance, December 31, 2006	81,461	$	1,028,101	$	242,667		$	(175,528	)	$	1,095,240
Comprehensive income:
Net income	—		—		6,764			—			6,764
Net unrealized gains on securities arising during the period, net of taxes of $6,406	—		—		—			9,701			9,701
Defined benefit pension plans—amortization of net loss, prior service gain and transition obligation included in net periodic pension cost, net of taxes of $1,400	—		—		—			2,200			2,200

Comprehensive income	—		—		6,764			11,901			18,665

Adjustment to initially apply FIN 48	—		—		(228	)		—			(228	)
Issuance of common stock, net	363		8,148		—			—			8,148
Common stock dividends ($0.31 per share)	—		—		(25,257	)		—			(25,257	)

Balance, March 31, 2007	81,824	$	1,036,249	$	223,946		$	(163,627	)	$	1,096,568

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

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)


Three months ended March 31	2008			2007
(in thousands)
Cash flows from operating activities
Net income	$	33,967		$	6,764
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment		37,882			36,856
Other amortization		2,860			2,680
Provision for loan losses		900			—
Writedown of utility plant		—			11,701
Deferred income taxes		(5,874	)		(5,908	)
Allowance for equity funds used during construction		(1,901	)		(1,232	)
Excess tax benefits from share-based payment arrangements		(28	)		(233	)
Loans receivable originated and purchased, held for sale		(66,664	)		(11,017	)
Proceeds from sale of loans receivable, held for sale		67,223			17,749
Changes in assets and liabilities
Decrease (increase) in accounts receivable and unbilled revenues, net		(3,857	)		27,745
Increase in fuel oil stock		(9,269	)		(2,403	)
Increase in accounts payable		11,667			7,049
Decrease in taxes accrued		(41,888	)		(34,828	)
Changes in other assets and liabilities		950			(4,022	)

Net cash provided by operating activities		25,968			50,901

Cash flows from investing activities
Available-for-sale investment and mortgage-related securities purchased		(66,145	)		(132,195	)
Principal repayments on available-for-sale investment and mortgage-related securities		132,885			108,556
Proceeds from sale of available-for-sale investment and mortgage-related securities		935			—
Net proceeds from sale of investments		—			2,536
Net increase in loans held for investment		(52,401	)		(41,232	)
Capital expenditures		(48,882	)		(35,521	)
Contributions in aid of construction		3,836			2,495
Other		(57	)		1

Net cash used in investing activities		(29,829	)		(95,360	)

Cash flows from financing activities
Net increase (decrease) in deposit liabilities		(16,904	)		1,525
Net increase (decrease) in short-term borrowings with original maturities of three months or less		107,501			(65,866	)
Proceeds from short-term borrowings with original maturities of greater than three months		—			13,008
Net increase in retail repurchase agreements		14,432			23,370
Proceeds from other bank borrowings		152,500			238,988
Repayments of other bank borrowings		(188,600	)		(238,813	)
Proceeds from issuance of long-term debt		9,897			215,679
Repayment of long-term debt		(50,000	)		(126,000	)
Excess tax benefits from share-based payment arrangements		28			233
Net proceeds from issuance of common stock		6,314			2,411
Common stock dividends		(20,676	)		(20,166	)
Decrease in cash overdraft		(8,582	)		(11,280	)
Other		(4,761	)		(5,034	)

Net cash provided by financing activities		1,149			28,055

Net decrease in cash and equivalents and federal funds sold		(2,712	)		(16,404	)
Cash and equivalents and federal funds sold, beginning of period		209,855			257,301

Cash and equivalents and federal funds sold, end of period	$	207,143		$	240,897

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.

In the opinion of HEI’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to present fairly the Company’s financial position as of March 31, 2008 and December 31, 2007 and the results of its operations and cash flows for the three months ended March 31, 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 March 31, 2008
Revenues from external customers	$	623,849		$	105,844	$	(76	)	$	729,617
Intersegment revenues (eliminations)		40			—		(40	)		—

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

Profit (loss)*		39,806			23,341		(9,460	)		53,687
Income taxes (benefit)		15,221			8,765		(4,266	)		19,720

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

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

Three months ended March 31, 2007
Revenues from external customers	$	447,608		$	104,460	$	1,955		$	554,023
Intersegment revenues (eliminations)		70			—		(70	)		—

Revenues		447,678			104,460		1,885			554,023

Profit (loss)*		140			18,399		(9,152	)		9,387
Income taxes (benefit)		(313	)		6,803		(3,867	)		2,623

Net income (loss)		453			11,596		(5,285	)		6,764

Assets (at March 31, 2007)		3,050,554			6,845,576		26,446			9,922,576

*	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 contingencies, see pages 15 through 35.

(4) Bank subsidiary

Selected financial information

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

Consolidated Statements of Income Data (unaudited)


Three months ended March 31	2008		2007
(in thousands)
Interest and dividend income
Interest and fees on loans	$	63,465	$	60,281
Interest and dividends on investment and mortgage-related securities		24,451		28,165

		87,916		88,446

Interest expense
Interest on deposit liabilities		18,220		20,738
Interest on other borrowings		19,149		18,406

		37,369		39,144

Net interest income		50,547		49,302
Provision for loan losses		900		—

Net interest income after provision for loan losses		49,647		49,302

Noninterest income
Fees from other financial services		6,823		6,501
Fee income on deposit liabilities		6,794		6,055
Fee income on other financial products		1,804		2,012
Gain on sale of securities		935		—
Other income		1,572		1,446

		17,928		16,014

Noninterest expense
Compensation and employee benefits		18,240		18,396
Occupancy		5,397		4,948
Equipment		3,114		3,478
Services		5,673		8,358
Data processing		2,616		2,557
Other expense		9,194		9,180

		44,234		46,917

Income before income taxes		23,341		18,399
Income taxes		8,765		6,803

Net income for common stock	$	14,576	$	11,596

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

Consolidated Balance Sheet Data (unaudited)


(in thousands)	March 31, 2008			December 31, 2007
Assets
Cash and equivalents	$	173,230		$	140,023
Federal funds sold		17,184			64,000
Available-for-sale investment and mortgage-related securities		2,086,037			2,140,772
Investment in stock of Federal Home Loan Bank of Seattle		97,764			97,764
Loans receivable, net		4,153,950			4,101,193
Other		233,249			234,661
Goodwill, net		83,080			83,080

	$	6,844,494		$	6,861,493

Liabilities and stockholder’s equity
Deposit liabilities–noninterest-bearing	$	678,934		$	652,055
Deposit liabilities–interest-bearing		3,651,422			3,695,205
Other borrowings		1,789,157			1,810,669
Other		123,646			108,800

		6,243,159			6,266,729

Common stock		326,193			325,467
Retained earnings		285,088			287,710
Accumulated other comprehensive loss, net of tax benefits		(9,946	)		(18,413	)

		601,335			594,764

	$	6,844,494		$	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 $807 million and $982 million, respectively, as of March 31, 2008 and $765 million and $1 billion, respectively, as of December 31, 2007.

As of March 31, 2008, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.3 billion.

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. 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. 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 has 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 the beginning of 2008. 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.

In accordance with FASB Staff Position No. FAS 157-2, the Company has delayed the application of SFAS No. 157 to ASB’s goodwill.

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	March 31, 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	$	2,086	$	—	$	2,086	$	—

Unrealized gains for the first quarter of 2008 were $15 million and were included in other comprehensive income.

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 an unobservable market assumption. These adjustments to fair value usually result from the application of lower-of-cost-or-market accounting or write-downs of individual loans. Unobservable assumptions reflect ASB’s own estimate of the fair value of collateral used in valuing the loan.

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


			Fair value measurements using
Description	March 31, 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	$	9.0	$	—	$	0.2	$	8.8

Specific reserves for the first quarter of 2008 were $5.6 million and were included in loans receivable held for investment, net. For the three months ended March 31, 2008, there were no adjustments to fair value for ASB’s loans held for sale.

Subsequent event.

In the second quarter of 2008, ASB shifted its strategy on an existing technology project designed to automate many of its workflows. ASB determined that alternatives are available that would result in lower net expenses compared to costs necessary to complete and maintain the current project. ASB made a decision to terminate further work on the project and redeploy its internal resources on other solutions designed to improve ASB’s efficiency. A pretax write-off of $1.9 million ($1.2 million after tax) for the disposal of software was recorded in the second quarter of 2008.

(5) Retirement benefits

Defined benefit plans.

For the first quarter of 2008, HECO contributed $0.9 million and HEI contributed $0.2 million to their respective retirement benefit plans, compared to $0.3 million and nil, respectively, in the first quarter of 2007. The Company’s current estimate of contributions to its retirement benefit plans in 2008 is $14.3 million (including $13.6 million to be made by the utilities and $0.7 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 million of benefits in 2008, comparable to the $1 million paid in 2007.

For the first quarter of 2008, the Company’s defined benefit retirement plans’ assets generated a loss, including investment management fees, of 7.7%. The market value of the defined benefit retirement plans’ assets as of March 31, 2008 was $1.0 billion compared to $1.1 billion at December 31, 2007, a decline of approximately $93 million.

The components of net periodic benefit cost were as follows:


	Pension benefits						Other benefits
Three months ended March 31	2008 (1)			2007			2008			2007
(in thousands)
Service cost	$	6,856		$	7,753		$	1,165		$	1,231
Interest cost		14,876			14,420			2,838			2,860
Expected return on plan assets		(18,232	)		(17,102	)		(2,740	)		(2,298	)
Amortization of unrecognized transition obligation		1			1			785			785
Amortization of prior service cost (gain)		(90	)		(49	)		3			3
Recognized actuarial loss		1,690			2,855			—			—

Net periodic benefit cost		5,101			7,878			2,051			2,581
Impact of PUC D&Os		1,657			—			193			—

Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	6,758		$	7,878		$	2,244		$	2,581

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

The Company recorded retirement benefits expense of $7 million and $8 million in the first quarters 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 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 quarter of 2008, ASB’s total expense for its employees participating in the HEI retirement savings plan was $1.1 million and contributions were $0.5 million. ASB’s current estimate of contributions to the retirement savings plan in 2008 is $2.1 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 (4,768,791 shares available for issuance under outstanding and future grants and awards as of March 31, 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 March 31
($ in millions)	2008	2007
Share-based compensation expense ¹	0.3	0.3
Income tax benefit	0.1	0.1

¹	The Company has not capitalized any share-based compensation cost. The estimated forfeiture rate for SARs was 5.0% and the estimated forfeiture rate for restricted stock was 12.7%.

Nonqualified stock options.

Information about HEI’s NQSOs is summarized as follows:


March 31, 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 –17.63	48,300	1.3	$	17.62
2000		14.74	52,000	2.1		14.74
2001		17.96	83,000	2.9		17.96
2002		21.68	134,000	3.8		21.68
2003		20.49	274,500	4.7		20.49

	$	14.74 –21.68	591,800	3.7	$	19.67

As of December 31, 2007, NQSOs outstanding totaled 603,800, with a weighted-average exercise price of $19.68. As of March 31, 2008, NQSO shares outstanding and NQSOs exercisable had an aggregate intrinsic value (including dividend equivalents) of $4.6 million.

NQSO activity and statistics are summarized as follows:


	Three months ended March 31
($ in thousands, except prices)	2008		2007
Shares granted		—		—
Shares forfeited		—		—
Shares expired		—		—
Shares vested		—		1,500
Aggregate fair value of vested shares		—	$	7
Shares exercised		12,000		19,500
Weighted-average exercise price	$	20.49	$	21.47
Cash received from exercise	$	246	$	419
Intrinsic value of shares exercised ¹	$	84	$	142
Tax benefit realized for the deduction of exercises	$	33	$	55
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 March 31, 2008, all NQSOs were vested.

Stock appreciation rights.

Information about HEI’s SARs is summarized as follows:


March 31, 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	325,000	3.8	$	26.02	283,000	3.5	$	26.02
2005		26.18	532,000	5.0		26.18	196,000	1.4		26.18

	$	26.02 –26.18	857,000	4.5	$	26.12	479,000	2.6	$	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 March 31, 2008, the SARs outstanding and exercisable (including dividend equivalents) had no intrinsic value.

SARs activity and statistics are summarized as follows:


	Three months ended March 31
($ in thousands, except prices)	2008		2007
Shares granted		—		—
Shares forfeited		—		—
Shares expired		—		—
Shares vested		15,000		6,000
Aggregate fair value of vested shares	$	87	$	36
Shares exercised		—		4,000
Weighted-average exercise price		—	$	26.18
Cash received from exercise		—		—
Intrinsic value of shares exercised ¹		—	$	3
Tax benefit realized for the deduction of exercises		—	$	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 March 31, 2008, there was $0.4 million of total unrecognized compensation cost related to SARs and that cost is expected to be recognized over a weighted average period of 1.0 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 three months ended March 31, 2008 and 2007 a total of 6,125 and 45,652 dividend equivalent shares for NQSO and SAR grants were distributed to SOIP participants, respectively. Section 409A, which amended the rules on deferred compensation, required the Company to change the way certain affected dividend equivalents are paid in order to avoid significant adverse tax consequences to the SOIP participants. Generally dividend equivalents subject to Section 409A will be paid within 2¹/2 months after the end of the calendar year. Upon retirement, an SOIP participant may elect to take distributions of dividend equivalents subject to Section 409A at the time of retirement or at the end of the calendar year.

Restricted stock

As of December 31, 2007, restricted stock shares outstanding totaled 146,000, with a weighted-average grant date fair value of $25.82. As of March 31, 2008, restricted stock shares outstanding totaled 140,000, with a weighted-average grant date fair value of $25.80. 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.

During the first quarter of 2008, no shares of restricted stock were granted, no restricted stock shares were vested and 6,000 shares of restricted stock with a grant date fair market value of $0.2 million were forfeited. During the first quarter of 2007, 8,700 shares of restricted stock with a grant date fair market value of $0.2 million were granted, no shares of restricted stock vested and no restricted stock shares were forfeited. The tax benefit realized for the tax deductions from restricted stock dividends were immaterial for the first quarters of 2008 and 2007.

As of March 31, 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.

In April 2008, 42,700 shares of restricted stock were granted to officers and key employees with a grant date fair market value of $1.1 million.

(7) Commitments and contingencies

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

(8) Cash flows

Supplemental disclosures of cash flow information

For the three months ended March 31, 2008 and 2007, the Company paid interest (net of amounts capitalized and including bank interest) to non-affiliates amounting to $50 million and $56 million, respectively.

For the three months ended March 31, 2008 and 2007, the Company paid income taxes amounting to $38 million and $3 million, respectively. The significant increase in taxes paid in the first quarter of 2008 versus 2007 was due primarily to the difference in the taxes due with the extensions for tax years 2007 and 2006. Estimated taxes paid during the year are based on the timing of taxable income generated during the year. In 2007, taxable income was significantly larger in the fourth quarter when compared to the first three quarters, resulting in a larger portion of the 2007 taxes paid with the extension filed in the first quarter of 2008.

Supplemental disclosures of noncash activities

Noncash increases in common stock for director and officer compensatory plans of the Company were $0.6 million and $0.5 million for the three months ended March 31, 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 $5 million for each of the three months ended March 31, 2008 and 2007. From March 23, 2004 to March 5, 2007, HEI satisfied the requirements of the HEI DRIP and the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) by acquiring for cash its common shares through open market purchases rather than the issuance of additional shares. On March 6, 2007, HEI began satisfying those requirements by the issuance of additional shares.

(9) Recent accounting pronouncements and interpretations

The fair value option for financial assets and financial liabilities

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, Including an amendment of FASB Statement No. 115.” SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value, which should improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The Company adopted SFAS No. 159 on January 1, 2008 and the adoption had no impact on the Company’s financial statements as the Company did not choose to measure additional items at fair value.

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. Management has not yet determined what further impact, if any, the adoption of SFAS No. 160 will have on the Company’s financial statements.

Written loan commitments

In November 2007, the SEC issued Staff Accounting Bulletin (SAB) No. 109, “Written Loan Commitments Recorded at Fair Value through Earnings,” which supersedes SAB No. 105, “Application of Accounting Principles to Loan Commitments.” SAB No. 109 states that the expected net future cash flows related to the associated servicing of the loan should be included in the measurement of all written loan commitments that are accounted for at fair value through earnings. Previously, SAB No. 105 stated that in measuring the fair value of a derivative loan commitment, a company should not incorporate the expected net future cash flows related to the associated servicing of the loan. SAB No. 109 is effective for loan commitments issued or modified in fiscal quarters beginning after December 15, 2007. ASB adopted SAB No. 109 in the first quarter of 2008 and the adoption had an immaterial impact on the Company’s financial statements.

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)


	Three months ended March 31
(in thousands, except ratio of earnings to fixed charges)	2008			2007
Operating revenues	$	622,494		$	446,797

Operating expenses
Fuel oil		249,543			159,929
Purchased power		150,795			111,516
Other operation		55,579			47,193
Maintenance		23,613			27,336
Depreciation		35,434			34,267
Taxes, other than income taxes		57,486			42,547
Income taxes		15,378			4,506

		587,828			427,294

Operating income		34,666			19,503

Other income (loss)
Allowance for equity funds used during construction		1,901			1,232
Other, net		1,096			(6,198	)

		2,997			(4,966	)

Income before interest and other charges		37,663			14,537

Interest and other charges
Interest on long-term debt		11,724			11,496
Amortization of net bond premium and expense		631			546
Other interest charges		986			2,141
Allowance for borrowed funds used during construction		(762	)		(598	)
Preferred stock dividends of subsidiaries		229			229

		12,808			13,814

Income before preferred stock dividends of HECO		24,855			723
Preferred stock dividends of HECO		270			270

Net income for common stock	$	24,585		$	453

Ratio of earnings to fixed charges (SEC method)		3.77			.99

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

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)


(in thousands, except par value)	March 31, 2008			December 31, 2007
Assets
Utility plant, at cost
Land	$	38,159		$	38,161
Plant and equipment		4,160,730			4,131,226
Less accumulated depreciation		(1,671,134	)		(1,647,113	)
Plant acquisition adjustment, net		28			41
Construction in progress		165,020			151,179

Net utility plant		2,692,803			2,673,494

Current assets
Cash and equivalents		15,250			4,678
Customer accounts receivable, net		153,923			146,112
Accrued unbilled revenues, net		110,456			114,274
Other accounts receivable, net		7,006			6,915
Fuel oil stock, at average cost		101,140			91,871
Materials and supplies, at average cost		35,239			34,258
Prepayments and other		8,378			9,490

Total current assets		431,392			407,598

Other long-term assets
Regulatory assets		283,498			284,990
Unamortized debt expense		15,325			15,635
Other		45,581			42,171

Total other long-term assets		344,404			342,796

	$	3,468,599		$	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		735,200			724,704
Accumulated other comprehensive income, net of income taxes		1,214			1,157

Common stock equity		1,121,015			1,110,462
Cumulative preferred stock – not subject to mandatory redemption		34,293			34,293
Long-term debt, net		895,028			885,099

Total capitalization		2,050,336			2,029,854

Current liabilities
Short-term borrowings–nonaffiliates		89,108			28,791
Accounts payable		138,349			137,895
Interest and preferred dividends payable		17,883			14,719
Taxes accrued		148,531			189,637
Other		51,124			57,799

Total current liabilities		444,995			428,841

Deferred credits and other liabilities
Deferred income taxes		156,197			162,113
Regulatory liabilities		268,890			261,606
Unamortized tax credits		58,581			58,419
Other		188,753			183,318

Total deferred credits and other liabilities		672,421			665,456

Contributions in aid of construction		300,847			299,737

	$	3,468,599		$	3,423,888

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Changes in Stockholder’s Equity (unaudited)


	Common stock			Premium on capital		Retained			Accumulated other comprehensive
(in thousands, except per share amounts)	Shares	Amount		stock		earnings			income (loss)			Total
Balance, December 31, 2007	12,806	$	85,387	$	299,214	$	724,704		$	1,157		$	1,110,462
Comprehensive income:
Net income	—		—		—		24,585			—			24,585
Retirement benefit plans:
Amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes of $870	—		—		—		—			1,366			1,366
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory asset, net of taxes of $834	—		—		—		—			(1,309	)		(1,309	)

Comprehensive income	—		—		—		24,585			57			24,642

Common stock dividends	—		—		—		(14,089	)		—			(14,089	)

Balance, March 31, 2008	12,806	$	85,387	$	299,214	$	735,200		$	1,214		$	1,121,015

Balance, December 31, 2006	12,806	$	85,387	$	299,214	$	700,252		$	(126,650	)	$	958,203
Comprehensive income:
Net income	—		—		—		453			—			453
Defined benefit retirement plans— amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes of $1,268	—		—		—		—			1,961			1,961

Comprehensive income	—		—		—		453			1,961			2,414

Adjustment to initially apply FIN 48	—		—		—		(620	)		—			(620	)

Balance, March 31, 2007	12,806	$	85,387	$	299,214	$	700,085		$	(124,689	)	$	959,997

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)


Three months ended March 31	2008			2007
(in thousands)
Cash flows from operating activities
Income before preferred stock dividends of HECO	$	24,855		$	723
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities
Depreciation of property, plant and equipment		35,434			34,267
Other amortization		2,163			1,306
Writedown of utility plant		—			11,701
Deferred income taxes		(5,953	)		(8,166	)
Tax credits, net		435			583
Allowance for equity funds used during construction		(1,901	)		(1,232	)
Changes in assets and liabilities
Decrease (increase) in accounts receivable		(7,902	)		12,118
Decrease in accrued unbilled revenues		3,818			14,980
Increase in fuel oil stock		(9,269	)		(2,403	)
Increase in materials and supplies		(981	)		(1,926	)
Increase in regulatory assets		(2,326	)		(1,603	)
Increase (decrease) in accounts payable		454			(2,475	)
Decrease in taxes accrued		(41,106	)		(36,961	)
Changes in other assets and liabilities		9,528			7,706

Net cash provided by operating activities		7,249			28,618

Cash flows from investing activities
Capital expenditures		(47,729	)		(34,822	)
Contributions in aid of construction		3,836			2,495
Other		(57	)		—

Net cash used in investing activities		(43,950	)		(32,327	)

Cash flows from financing activities
Common stock dividends		(14,089	)		—
Preferred stock dividends		(270	)		(270	)
Proceeds from issuance of long-term debt		9,897			215,679
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		60,317			(65,865	)
Decrease in cash overdraft		(8,582	)		(11,280	)

Net cash provided by financing activities		47,273			12,264

Net increase in cash and equivalents		10,572			8,555
Cash and equivalents, beginning of period		4,678			3,859

Cash and equivalents, end of period	$	15,250		$	12,414

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.

In the opinion of HECO’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to present fairly the financial position of HECO and its subsidiaries as of March 31, 2008 and December 31, 2007 and the results of their operations and cash flows for the three months ended March 31, 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 March 31, 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 three months ended March 31, 2008 and 2007 each consisted of $0.8 million of interest income received from the 2004 Debentures; $0.8 million of distributions to holders of the Trust Preferred Securities; and $25,000 of common dividends on the trust common securities to HECO. So long as the 2004 Trust Preferred Securities are outstanding, HECO is not entitled to receive any funds from Trust III other than pro rata distributions, subject to certain subordination provisions, on the trust common securities. In the event of a default by HECO in the performance of its obligations under the 2004 Debentures or under its Guarantees, or in the event HECO, HELCO or MECO elect to defer payment of interest on any of their respective 2004 Debentures, then HECO will be subject to a number of restrictions, including a prohibition on the payment of dividends on its common stock.

Purchase power agreements

As of March 31, 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 that supplied as-available energy. Approximately 91% of the 540 MW of firm capacity is under PPAs, entered into before December 31, 2003, with AES Hawaii, Inc. (AES Hawaii), Kalaeloa Partners, L.P. (Kalaeloa), Hamakua Energy Partners, L.P. (HEP) and HPOWER. Purchases from all IPPs for the three months ended March 31, 2008 totaled $151 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $36 million, $51 million, $20 million and $13 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 windfarm provided information as required under the PPA. Management has concluded that the consolidation of two entities owning windfarms 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 three months ended March 31, 2008 and 2007, HECO and its subsidiaries included approximately $55 million and $40 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

(4) Retirement benefits

Defined benefit plans

For the first quarter of 2008, HECO and its subsidiaries contributed $0.9 million to their retirement benefit plans, compared to $0.3 million in the first quarter of 2007. HECO and its subsidiaries’ current estimate of contributions to their retirement benefit plans in 2008 is $13.6 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 quarter of 2008, HECO and its subsidiaries’ defined benefit retirement plans’ assets generated a loss, including investment management fees, of 7.7%. The market value of the defined benefit retirement plan’s assets as of March 31, 2008 was $0.9 billion compared to $1.0 billion at December 31, 2007, a decline of approximately $85 million.

The components of net periodic benefit cost were as follows:


	Pension benefits						Other benefits
Three months ended March 31	2008			2007			2008			2007
(in thousands)
Service cost	$	6,533		$	6,331		$	1,135		$	1,200
Interest cost		13,445			12,822			2,755			2,787
Expected return on plan assets		(16,251	)		(15,224	)		(2,695	)		(2,257	)
Amortization of unrecognized transition obligation		—			—			782			782
Amortization of prior service gain		(191	)		(190	)		—			—
Recognized actuarial loss		1,645			2,616			—			—

Net periodic benefit cost		5,181			6,355			1,977			2,512
Impact of PUC D&Os		1,657			—			193			—

Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	6,838		$	6,355		$	2,170		$	2,512

HECO and its subsidiaries recorded retirement benefits expense of $7 million in each of the first quarters 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.

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.

(5) Commitments and contingencies

Interim increases

On April 4, 2007, the PUC issued an interim D&O in HELCO’s 2006 test year rate case granting a general rate increase on the island of Hawaii of 7.58%, or $24.6 million, which was implemented on April 5, 2007.

On October 22, 2007, the PUC issued, and HECO immediately implemented, an interim D&O in HECO’s 2007 test year rate case, granting HECO an increase of $69.997 million in annual revenues over current effective rates at the time of the interim decision.

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 $13.2 million in annual revenues, or a 3.7% increase.

As of March 31, 2008, HECO and its subsidiaries had recognized $72 million of revenues with respect to interim orders ($15 million related to interim orders regarding certain integrated resource planning costs and $57 million related to interim orders with respect to interim surcharges to recover general rate increase requests.)

Energy cost adjustment clauses

On June 19, 2006, the PUC issued an order in HECO’s 2005 test year rate case indicating that the record in the pending case had not been developed for the purpose of addressing the factors in Act 162, signed into law by the Governor of Hawaii on June 2, 2006. Act 162 states that any automatic fuel rate adjustment clause requested by a public utility in an application filed with the PUC shall be designed, as determined in the PUC’s discretion, to (1) fairly share the risk of fuel cost changes between the public utility and its customers, (2) provide the public utility with sufficient incentive to reasonably manage or lower its fuel costs and encourage greater use of renewable energy, (3) allow the public utility to mitigate the risk of sudden or frequent fuel cost changes that cannot otherwise reasonably be mitigated through other commercially available means,

such as through fuel hedging contracts, (4) preserve, to the extent reasonably possible, the public utility’s financial integrity, and (5) minimize, to the extent reasonably possible, the public utility’s need to apply for frequent applications for general rate increases to account for the changes to its fuel costs. While the PUC already had reviewed the automatic fuel rate adjustment clause in rate cases, Act 162 required 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 stated it would not require the parties in the rate case proceeding to file a stipulated procedural schedule on this issue, but that it expects HECO and HELCO to develop information relating to the Act 162 factors for examination during their next rate case proceedings.

The ECAC provisions of Act 162 were reviewed in the HELCO rate case based on a 2006 test year and are being reviewed in the HECO and MECO rate cases based on 2007 test years. 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. On April 4, 2007, the PUC issued an interim D&O in the HELCO 2006 test year rate case which reflected the continuation of HELCO’s ECAC, consistent with a settlement agreement reached between HELCO and the Consumer Advocate.

In an order issued on August 24, 2007, the PUC added as an issue to be addressed in HECO’s 2007 test year rate case whether HECO’s ECAC complies with the requirements of Act 162 as codified in the Hawaii Revised Statutes. On September 6, 2007, HECO, the Consumer Advocate and the federal Department of Defense (DOD) (the Parties) executed and filed an agreement on most of the issues in HECO’s 2007 test year rate case proceeding. 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 in this proceeding. On October 22, 2007, the PUC issued an interim D&O in HECO’s 2007 test year rate case which reflected the continuation of HECO’s ECAC for purposes of the interim increase, consistent with the agreement reached among the Parties. 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 have agreed that their resolution of the ECAC issue will not affect their agreement regarding revenue requirements in the proceeding. Management cannot predict the ultimate effect of the required Act 162 analysis on the continuation of the electric utilities’ existing ECACs.

In an order issued on June 19, 2007, the PUC approved a procedural order for MECO’s 2007 test year rate case and required MECO and the Consumer Advocate (the parties) to address an additional issue of whether MECO’s ECAC complies with the requirements of Act 162 as codified in the Hawaii Revised Statutes. In its direct testimony, the Consumer Advocate concluded that the ECAC’s fixed efficiency factors are an effective means of sharing the operating and performance risks between MECO’s ratepayers and shareholders and that MECO’s ECAC provides a fair sharing of the risks of fuel cost changes between MECO and its ratepayers in a manner that preserves the financial integrity of MECO without the need for frequent rate filings. On December 7, 2007, the parties filed a stipulated settlement letter for this proceeding in which the parties agreed, among other things, that no further changes are required to MECO’s ECAC in order to comply with the requirements of Act 162. On December 21, 2007 the PUC issued an interim D&O in MECO’s 2007 test year rate case which reflected the continuation of MECO’s ECAC for purposes of the interim increase, consistent with the agreement reached among the parties.

On April 23, 2007, the PUC issued an order denying HECO’s proposal to recover $2.4 million, including revenue taxes, of distributed generation fuel and trucking and low sulfur fuel oil (LFSO) trucking costs since January 1, 2006 through the reconciliation process for the ECAC. However, the PUC allowed HECO to establish and implement a new and separate interim surcharge to recover its additional DG and LFSO costs on a going forward basis. HECO implemented an interim surcharge to recover such costs incurred from May 1, 2007.

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 commenced engineering, design and certain construction work for ST-7 and anticipates an in-service date in mid-2009. As of March 31, 2008, HELCO’s cost estimate for ST-7 was $92 million (of which $19 million had been incurred) and outstanding commitments for materials, equipment and outside services totaled $28 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.

East Oahu Transmission Project (EOTP)

HECO transmits bulk power to the Honolulu/East Oahu area over two major transmission corridors (Northern and Southern). HECO had planned to construct a partial underground/partial overhead 138 kilovolt (kV) line from the Kamoku substation to the Pukele substation, which serves approximately 16% of Oahu’s electrical load, including Waikiki, in order to close the gap between the Southern and Northern corridors and provide a third transmission line to the Pukele substation. In total, this additional transmission capacity would benefit an area that comprises approximately 56% of the power demand on Oahu. However, in June 2002, an application for a permit which would have allowed construction in the originally planned route through conservation district lands was denied.

HECO continued to believe that the proposed reliability project (the East Oahu Transmission Project) was needed and, in December 2003, filed an application with the PUC requesting approval to commit funds (currently estimated at $74 million; see costs incurred below) for a revised EOTP using a 46 kV system. In March 2004, the PUC granted intervener status to an environmental organization and three elected officials (collectively treated as one party), and a more limited participant status to four community organizations. The environmental review process for the revised EOTP was completed and the PUC issued a Finding of No Significant Impact in April 2005.

In written testimony filed in June 2005, the 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 in 2002 of the approval necessary for the partial underground/partial overhead 138 kV line, and the related allowance for funds used during construction (AFUDC) of $5 million. In rebuttal testimony filed in August 2005, 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 addressed. The PUC held an evidentiary hearing on HECO’s application in November 2005, and post-hearing briefing was completed in March 2006. Just prior to the November 2005 evidentiary hearing, the PUC approved that part of a stipulation between HECO and the Consumer Advocate providing that (i) this proceeding should determine whether HECO should be given approval to expend funds for

the EOTP, but with the understanding that no part of the EOTP costs may be recovered from ratepayers unless and until the PUC grants HECO recovery in a rate case (which is consistent with other projects) and (ii) the issue as to whether the pre-2003 planning and permitting costs, and related AFUDC, should be included in the project costs is reserved to, and may be raised in, the next HECO rate case (or other proceeding) in which HECO seeks approval to recover the EOTP costs. In October 2007, the PUC issued a final D&O approving HECO’s request to expend funds for a revised EOTP using a 46 kV system, 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 revised project, none of which is in conservation district lands, in two phases. The first phase is currently projected to be completed in 2010 and the projected completion date of the second phase is being evaluated.

As of March 31, 2008, the accumulated costs recorded for the EOTP amounted to $34 million, including (i) $12 million of planning and permitting costs incurred prior to 2003, (ii) $6 million of planning and permitting costs incurred after 2002 and (iii) $16 million for AFUDC. Management believes no adjustment to project costs is required as of March 31, 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.

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 1995, the Department of Health of the State of Hawaii (DOH) issued letters indicating that it had identified a number of parties, including HECO, who appeared to be potentially responsible for historical subsurface petroleum contamination and/or operated their facilities upon petroleum-contaminated land at or near Honolulu Harbor in the Iwilei district of Honolulu. Certain of the identified parties formed a work group to determine the nature and extent of any contamination and appropriate response actions, as well as to identify additional potentially responsible parties (PRPs). The U.S. Environmental Protection Agency (EPA) became involved in the investigation in June 2000. Later in 2000, the DOH issued notices to additional PRPs. The parties in the work group and some of the new PRPs (collectively, the Participating Parties) entered into a joint defense agreement and signed a voluntary response agreement with the DOH. The Participating Parties agreed to fund 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.

In 2001, management developed and expensed a preliminary estimate of HECO’s share of costs for continuing investigative work, remedial activities and monitoring at the Iwilei Unit of $1.1 million. Since 2001, subsurface investigation and assessment have been conducted and several preliminary oil removal tasks have been performed at the Iwilei Unit in accordance with notices of interest issued by the EPA and the DOH.

In 2003, HECO and other Participating Parties with active operations in the Iwilei area investigated their operations 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.

During 2006 and the beginning of 2007, the Participating Parties developed analyses of various remedial alternatives for two of the four remedial subunits of the Iwilei Unit. Draft analyses of remedial alternatives for the remaining two subunits of the Iwilei Unit were prepared in late 2007 and early 2008. The DOH will use the analyses to make a final determination of which remedial alternatives the PRPs will be required to implement. The DOH was scheduled to complete the final remediation determinations for all remedial subunits of the Iwilei Unit by the end of the first quarter of 2008, but has only approved two to date. HECO management developed an estimate of HECO’s share of the costs associated with implementing the Participating Parties’ recommended remedial approaches for the two subunits covered by the analyses of $1.2 million, which was expensed in 2006. Subsequently, based on the estimated costs for the remaining two subunits, as well as updated estimates for total remediation costs, HECO management expensed an additional $0.6 million in the third quarter of 2007. In April 2008, the Participating Parties’ consultant issued for review a draft Iwilei District Program Cost Estimate Report, a 30-year forecast of future program and remediation costs for all four subunits. Based on this draft report, in the first quarter of 2008, HECO accrued $0.4 million for additional future remediation costs. As of March 31, 2008, the remaining accrual (amounts expensed less amounts expended) related to the Iwilei Unit was $2 million.

Because (1) the full scope of additional investigative work, remedial activities and monitoring remain 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, which is located in the “Downtown” unit of the Honolulu Harbor site), the cost estimate may be subject to significant change and additional material investigative and remedial 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 has filed for a rehearing. If the ruling stands, however, the EPA will be 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.

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. Effective September 9, 2004, the EPA issued a rule, which established location and technology-based design, construction and capacity standards for existing cooling water intake structures. These standards applied to HECO’s Kahe, Waiau and Honolulu generating stations, unless the utility could demonstrate that at each facility implementation of these standards would result in costs either significantly higher than projected costs the EPA considered in establishing the standards for the facility (cost-cost test) or significantly greater than the benefits of meeting the standards (cost-benefit test). In either case, the EPA would then make a case-by-case determination of an appropriate performance standard. The regulation also would have allowed restoration of aquatic organism populations in lieu of meeting the standards. The rule required covered facilities to demonstrate compliance by March 2008. HECO had retained a consultant that was developing a cost effective compliance strategy and a preliminary assessment of technologies and operational measures under the rule.

On January 25, 2007, the U.S. Circuit Court for the Second Circuit issued a decision in Riverkeeper, Inc. v. EPA that remanded for further consideration and proceedings significant portions of the rule and found other portions of the rule to be impermissible. In particular, the Court determined that restoration and the cost-benefit test provisions of the rule were impermissible under the Clean Water Act. It also remanded the best technology available determination to permit the EPA to provide a reasoned explanation for its decision or a new determination. It remanded the cost-cost test for the EPA’s further consideration based on the best technology available determination and to afford adequate notice. On July 9, 2007, the EPA formally suspended the rule. In the suspension announcement, the EPA 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. Currently, this guidance does not affect the HECO facilities subject to the cooling water intake requirements because none of the facilities are subject to permit renewal until mid-2009. On April 14, 2008, the U. S. Supreme Court agreed to review the Court of Appeal’s decision. If the Court of Appeal’s decision stands, however, the ruling reduces the compliance options available to HECO. 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 March 31, 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 three months ended March 31, 2008 and 2007, HECO and its subsidiaries paid interest amounting to $9 million and $11 million, respectively.

For the three months ended March 31, 2008 and 2007, HECO and its subsidiaries paid income taxes amounting to $33 million and $6 million, respectively. The significant increase in taxes paid in the first quarter of 2008 versus 2007 was due primarily to the difference in the taxes due with the extensions for tax years 2007 and 2006. Estimated taxes paid during the year are based on the timing of taxable income generated during the year. In 2007, taxable income was significantly larger in the fourth quarter when compared to the first three quarters, resulting in a larger portion of the 2007 taxes paid with the extension filed in the first quarter of 2008.

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 $1.9 million and $1.2 million for the three months ended March 31, 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) Subsequent event

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. The final D&O authorized an increase of $44.9 million in annual revenues, or a 3.67% increase (or a net increase of $33 million or 2.7%), based on a 10.7% return on average common equity and an 8.66% return on rate base of $1.060 billion. As a result of the final D&O, HECO will be required to refund to customers certain differences between the amount that HECO has collected pursuant to the interim decision and the increase authorized in the final decision, retroactive to September 28, 2005 (the date the interim increase became effective), with interest through the refund period. Customer refunds, including interest, of approximately $16 million, which have been fully accrued (except for interest from April 1, 2008 to the time of the refund), will be reflected as a credit to customer bills, following approval by the PUC of HECO’s refund plan.

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


Three months ended March 31	2008			2007
(in thousands)
Operating income from regulated and nonregulated activities before income taxes (per HEI consolidated statements of income)	$	50,983		$	12,992
Deduct:
Income taxes on regulated activities		(15,378	)		(4,506	)
Revenues from nonregulated activities		(1,395	)		(881	)
Add:
Expenses from nonregulated activities		456			11,898

Operating income from regulated activities after income taxes (per HECO consolidated statements of income)	$	34,666		$	19,503

(10) 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 March 31, 2008


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

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

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

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

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

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

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

Interest and other charges
Interest on long-term debt		7,525		1,952		2,247		—		—		—			11,724
Amortization of net bond premium and expense		400		107		124		—		—		—			631
Other interest charges		862		405		82		—		—		(363	)		986
Allowance for borrowed funds used during construction		(585	)	(117	)	(60	)	—		—		—			(762	)
Preferred stock dividends of subsidiaries		—		—		—		—		—		229			229

		8,202		2,347		2,393		—		—		(134	)		12,808

Income (loss) before preferred stock dividends of HECO		24,855		4,323		5,484		(23	)	(254	)	(9,530	)		24,855
Preferred stock dividends of HECO		270		134		95		—		—		(229	)		270

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Three months ended March 31, 2007


(in thousands)	HECO			HELCO		MECO		RHI		Reclassifications and eliminations		HECO consolidated
Operating revenues	$	288,690		78,809		79,298		—		—		$	446,797

Operating expenses
Fuel oil		101,062		20,038		38,829		—		—			159,929
Purchased power		78,300		27,062		6,154		—		—			111,516
Other operation		33,485		7,166		6,542		—		—			47,193
Maintenance		16,378		5,568		5,390		—		—			27,336
Depreciation		19,739		7,524		7,004		—		—			34,267
Taxes, other than income taxes		27,702		7,363		7,482		—		—			42,547
Income taxes		1,970		538		1,998		—		—			4,506

		278,636		75,259		73,399		—		—			427,294

Operating income		10,054		3,550		5,899		—		—			19,503

Other income
Allowance for equity funds used during construction		1,087		65		80		—		—			1,232
Equity in earnings of subsidiaries		(2,937	)	—		—		—		2,937			—
Other, net		1,485		(6,863	)	6		(15	)	(811	)		(6,198	)

		(365	)	(6,798	)	86		(15	)	2,126			(4,966	)

Income (loss) before interest and other charges		9,689		(3,248	)	5,985		(15	)	2,126			14,537

Interest and other charges
Interest on long-term debt		7,125		1,857		2,514		—		—			11,496
Amortization of net bond premium and expense		348		99		99		—		—			546
Other interest charges		2,022		757		173		—		(811	)		2,141
Allowance for borrowed funds used during construction		(529	)	(31	)	(38	)	—		—			(598	)
Preferred stock dividends of subsidiaries		—		—		—		—		229			229

		8,966		2,682		2,748		—		(582	)		13,814

Income (loss) before preferred stock dividends of HECO		723		(5,930	)	3,237		(15	)	2,708			723
Preferred stock dividends of HECO		270		134		95		—		(229	)		270

Net income (loss) for common stock	$	453		(6,064	)	3,142		(15	)	2,937		$	453

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

March 31, 2008


(in thousands)	HECO			HELCO		MECO		RHI	UBC	Reclassifications and Eliminations		HECO Consolidated
Assets
Utility plant, at cost
Land	$	28,831		4,982		4,346		—	—	—		$	38,159
Plant and equipment		2,521,374		835,187		804,169		—	—	—			4,160,730
Less accumulated depreciation		(998,826	)	(331,639	)	(340,669	)	—	—	—			(1,671,134	)
Plant acquisition adjustment, net		—		—		28		—	—	—			28
Construction in progress		114,743		39,088		11,189		—	—	—			165,020

Net utility plant		1,666,122		547,618		479,063		—	—	—			2,692,803

Investment in wholly owned subsidiaries, at equity		417,551		—		—		—	—	(417,551	)		—

Current assets
Cash and equivalents		10,495		3,043		1,504		170	38	—			15,250
Advances to affiliates		43,000		—		500		—	—	(43,500	)		—
Customer accounts receivable, net		102,630		27,444		23,849		—	—	—			153,923
Accrued unbilled revenues, net		77,175		17,334		15,947		—	—	—			110,456
Other accounts receivable, net		5,558		2,690		3,479		—	—	(4,721	)		7,006
Fuel oil stock, at average cost		74,033		10,116		16,991		—	—	—			101,140
Materials & supplies, at average cost		17,029		4,709		13,501		—	—	—			35,239
Prepayments and other		5,821		1,463		1,094		—	—	—			8,378

Total current assets		335,741		66,799		76,865		170	38	(48,221	)		431,392

Other long-term assets
Regulatory assets		209,195		39,627		34,676		—	—	—			283,498
Unamortized debt expense		10,355		2,403		2,567		—	—	—			15,325
Other		31,902		6,576		6,924		—	179	—			45,581

Total other long-term assets		251,452		48,606		44,167		—	179	—			344,404

	$	2,670,866		663,023		600,095		170	217	(465,772	)	$	3,468,599

Capitalization and liabilities
Capitalization
Common stock equity	$	1,121,015		206,014		211,194		159	184	(417,551	)	$	1,121,015
Cumulative preferred stock–not subject to mandatory redemption		22,293		7,000		5,000		—	—	—			34,293
Long-term debt, net		574,482		146,834		173,712		—	—	—			895,028

Total capitalization		1,717,790		359,848		389,906		159	184	(417,551	)		2,050,336

Current liabilities
Short-term borrowings-nonaffiliates		89,108		—		—		—	—	—			89,108
Short-term borrowings-affiliate		500		43,000		—		—	—	(43,500	)		—
Accounts payable		96,136		26,063		16,150		—	—	—			138,349
Interest and preferred dividends payable		11,103		3,213		3,683		—	—	(116	)		17,883
Taxes accrued		92,136		26,710		29,685		—	—	—			148,531
Other		35,583		10,116		9,986		11	33	(4,605	)		51,124

Total current liabilities		324,566		109,102		59,504		11	33	(48,221	)		444,995

Deferred credits and other liabilities
Deferred income taxes		126,548		17,639		12,010		—	—	—			156,197
Regulatory liabilities		186,031		47,619		35,240		—	—	—			268,890
Unamortized tax credits		32,749		13,042		12,790		—	—	—			58,581
Other		107,356		52,222		29,175		—	—	—			188,753

Total deferred credits and other liabilities		452,684		130,522		89,215		—	—	—			672,421

Contributions in aid of construction		175,826		63,551		61,470		—	—	—			300,847

	$	2,670,866		663,023		600,095		170	217	(465,772	)	$	3,468,599

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 Stockholder’s Equity (unaudited)

Three months ended March 31, 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		24,585		4,189		5,389		(23	)	(254	)	(9,301	)		24,585
Retirement benefit plans:
Amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes		1,366		190		153		—		—		(343	)		1,366
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory asset, net of taxes		(1,309	)	(185	)	(147	)	—		—		332			(1,309	)

Comprehensive income (loss)		24,642		4,194		5,395		(23	)	(254	)	(9,312	)		24,642
Common stock dividends		(14,089	)	—		(2,722	)	—		—		2,722			(14,089	)
Issuance of common stock		—		—		—		—		50		(50	)		—

Balance, March 31, 2008	$	1,121,015		206,014		211,194		159		184		(417,551	)	$	1,121,015

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Stockholder’s Equity (unaudited)

Three months ended March 31, 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		453		(6,064	)	3,142		(15	)	2,937			453
Defined benefit retirement plans—amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of tax benefits		1,961		263		219		—		(482	)		1,961

Comprehensive income (loss)		2,414		(5,801	)	3,361		(15	)	2,455			2,414

Adjustment to initially apply FIN 48, net of tax benefits		(620	)	(32	)	(42	)	—		74			(620	)

Balance, March 31, 2007	$	959,997		169,266		195,550		250		(365,066	)	$	959,997

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Three months ended March 31, 2008


(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and eliminations		HECO Consolidated
Cash flows from operating activities
Income before preferred stock dividends of HECO	$	24,855		4,323		5,484		(23	)	(254	)	(9,530	)	$	24,855
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Equity in earnings		(9,326	)	—		—		—		—		9,301			(25	)
Common stock dividends received from subsidiaries		2,747		—		—		—		—		(2,722	)		25
Depreciation of property, plant and equipment		20,552		7,834		7,048		—		—		—			35,434
Other amortization		792		197		1,174		—		—		—			2,163
Deferred income taxes		(4,055	)	(154	)	(1,744	)	—		—		—			(5,953	)
Tax credits, net		264		142		29		—		—		—			435
Allowance for equity funds used during construction		(1,502	)	(255	)	(144	)	—		—		—			(1,901	)
Changes in assets and liabilities:
Increase in accounts receivable		(3,402	)	(1,099	)	(2,874	)	—		—		(527	)		(7,902	)
Decrease (increase) in accrued unbilled revenues		5,375		(539	)	(1,018	)	—		—		—			3,818
Decrease (increase) in fuel oil stock		(16,744	)	2,378		5,097		—		—		—			(9,269	)
Decrease (increase) in materials and supplies		(1,306	)	(305	)	630		—		—		—			(981	)
Decrease (increase) in regulatory assets		(1,765	)	151		(712	)	—		—		—			(2,326	)
Increase (decrease) in accounts payable		(1,563	)	4,253		(2,236	)	—		—		—			454
Increase in taxes accrued		(26,896	)	(8,670	)	(5,540	)	—		—		—			(41,106	)
Changes in other assets and liabilities		7,286		850		884		(5	)	(14	)	527			9,528

Net cash provided by (used in) operating activities		(4,688	)	9,106		6,078		(28	)	(268	)	(2,951	)		7,249

Cash flows from investing activities
Capital expenditures		(23,006	)	(17,819	)	(6,904	)	—		—		—			(47,729	)
Contributions in aid of construction		1,629		1,406		801		—		—		—			3,836
Advances from (to) affiliates		(6,400	)	—		1,500		—		—		4,900			—
Investment in consolidated subsidiary		(50	)	—		—		—		—		50			—
Other		122		—		—		—		(179	)	—			(57	)

Net cash used in investing activities		(27,705	)	(16,413	)	(4,603	)	—		(179	)	4,950			(43,950	)

Cash flows from financing activities
Common stock dividends		(14,089	)	—		(2,722	)	—		—		2,722			(14,089	)
Preferred stock dividends		(270	)	(134	)	(95	)	—		—		229			(270	)
Proceeds from issuance of long-term debt		6,808		1,015		2,074		—		—		—			9,897
Proceeds from issuance of common stock		—		—		—		—		50		(50	)		—
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		58,817		6,400		—		—		—		(4,900	)		60,317
Other		(8,581	)	—		(1	)	—		—		—			(8,582	)

Net cash provided by (used in) financing activities		42,685		7,281		(744	)	—		50		(1,999	)		47,273

Net increase (decrease) in cash and equivalents		10,292		(26	)	731		(28	)	(397	)	—			10,572
Cash and equivalents, beginning of period		203		3,069		773		198		435		—			4,678

Cash and equivalents, end of period	$	10,495		3,043		1,504		170		38		—		$	15,250

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Three months ended March 31, 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	$	723		(5,930	)	3,237		(15	)	2,708		$	723
Adjustments to reconcile income (loss) before preferred stock dividends of HECO to net cash provided by (used in) operating activities
Equity in (earnings) loss		2,912		—		—		—		(2,937	)		(25	)
Common stock dividends received from subsidiaries		25		—		—		—		—			25
Depreciation of property, plant and equipment		19,739		7,524		7,004		—		—			34,267
Other amortization		875		(312	)	743		—		—			1,306
Writedown of utility plant		—		11,701		—		—		—			11,701
Deferred income taxes		(2,929	)	(4,845	)	(392	)	—		—			(8,166	)
Tax credits, net		348		217		18		—		—			583
Allowance for equity funds used during construction		(1,087	)	(65	)	(80	)	—		—			(1,232	)
Changes in assets and liabilities
Decrease (increase) in accounts receivable		11,848		2,846		(2,978	)	—		402			12,118
Decrease in accrued unbilled revenues		13,163		695		1,122		—		—			14,980
Decrease (increase) in fuel oil stock		(2,949	)	2,184		(1,638	)	—		—			(2,403	)
Increase in materials and supplies		(1,226	)	(256	)	(444	)	—		—			(1,926	)
Increase in regulatory assets		(632	)	(183	)	(788	)	—		—			(1,603	)
Increase (decrease) in accounts payable		1,510		(8,417	)	4,432		—		—			(2,475	)
Decrease in taxes accrued		(26,921	)	(5,395	)	(4,645	)	—		—			(36,961	)
Changes in other assets and liabilities		6,766		3,259		(1,920	)	3		(402	)		7,706

Net cash provided by (used in) operating activities		22,165		3,023		3,671		(12	)	(229	)		28,618

Cash flows from investing activities
Capital expenditures		(21,284	)	(8,727	)	(4,811	)	—		—			(34,822	)
Contributions in aid of construction		1,334		655		506		—		—			2,495
Advances to affiliates		8,600		—		(3,500	)	—		(5,100	)		—

Net cash used in investing activities		(11,350	)	(8,072	)	(7,805	)	—		(5,100	)		(32,327	)

Cash flows from financing activities
Preferred stock dividends		(270	)	(134	)	(95	)	—		229			(270	)
Proceeds from issuance of long-term debt		130,959		19,850		64,870		—		—			215,679
Repayment of long-term debt		(62,280	)	(8,020	)	(55,700	)	—		—			(126,000	)
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		(62,365	)	(3,600	)	(5,000	)	—		5,100			(65,865	)
Decrease in cash overdraft		(9,529	)	(1,705	)	(46	)	—		—			(11,280	)

Net cash provided by (used in) financing activities		(3,485	)	6,391		4,029		—		5,329			12,264

Net increase (decrease) in cash and equivalents		7,330		1,342		(105	)	(12	)	—			8,555
Cash and equivalents, beginning of period		2,328		738		518		275		—			3,859

Cash and equivalents, end of period	$	9,658		2,080		413		263		—		$	12,414

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) consolidated financial statements of HEI and HECO and accompanying notes.

HEI CONSOLIDATED

RESULTS OF OPERATIONS


(in thousands, except per share amounts)	Three months ended March 31				% change	Primary reason(s) for significant change*
(in thousands, except per share amounts)	2008		2007		% change	Primary reason(s) for significant change*
Revenues	$	729,617	$	554,023	32	Increase for the electric utility and the bank segments, slightly offset by decrease for the “other” segment

Operating income		70,746		28,541	148	Increase for the electric utility and the bank segments, slightly offset by an increase in losses for the “other” segment

Net income		33,967		6,764	402	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	$	0.41	$	0.08	413	Higher net income

Weighted-average number of common shares outstanding		83,472		81,448	2	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 rate for the first quarter of 2008 was 37%, compared to an effective tax rate for the first quarter of 2007 of 28%, which reflected the acceleration of the state tax credits associated with the write-off of a portion of CT-4 and CT-5 and the effect of state tax credits against a small income tax expense base.

Dividends

The payout ratios for 2007 and the first quarter of 2008 were 120% and 76%, respectively. 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

Note: The statistical data in this section is from public third party sources (e.g., State of Hawaii Department of Business, Economic Development and Tourism (DBEDT), U.S. Census Bureau and Bloomberg).

Because its core businesses provide local electric utility and banking services, the Company’s operating results are influenced by the strength of Hawaii’s economy.

In recent years, Hawaii’s economy experienced strong growth fueled by increases in tourism, military spending by the federal government to expand and revitalize its facilities, strength in the housing market and increases in residential and commercial construction. The state’s economic growth, which is fueled by the two largest components of Hawaii’s economy – tourism and the federal government – is forecast by DBEDT in its latest “Outlook for the Economy,” dated March 28, 2008, to moderate to 2.5% in 2008 and 2009.

Tourism saw record levels of growth in 2004 and 2005, but stabilized in 2006 and 2007. State economists expect visitor days and expenditures to decline 1.5% and increase by 1.5%, respectively, in 2008. However, at the end of March 2008 and beginning of April 2008, Aloha Airlines and ATA shut down mainland service resulting in the immediate loss of 1.1 million air seats – an estimated 15% of the flights between Hawaii and the mainland. Through March 2008, visitor arrivals were approximately 3% ahead of the same period in 2007. The closure of the two airline businesses resulted in a 14.3% decrease in domestic visitor arrivals for the first two weeks of April 2008 compared to the same period a year earlier, and will have a short-term effect on the visitor industry. It is too early to forecast the long-term impact. However, other carriers are adding airseats and the Hawaii Tourism Authority has stated its intention to take actions to mitigate the impacts of the airline closures.

Historically, tourism has been affected by the health of the U.S and Japanese economies. The real gross domestic product (GDP) growth in the U.S. is estimated to be 1.7% in 2008, compared to 2.5% in 2007. For Japan, real GDP is estimated to be 1.4% in 2008, compared to 2% in 2007.

Hawaii’s real estate market followed a pattern similar to tourism, showing record growth in 2004 and 2005 and slowing in 2006 and 2007. Median home prices on Oahu are slightly lower and home sales volume has slowed. Home sales on Oahu have decreased 23% during the first four months of 2008 compared to the same period a year ago. Median home prices have also declined to $639,000 in April 2008, down 3.9% compared to April 2007. The Hawaii real estate market appears to be holding relatively steady despite instability in the finance industry and negative market conditions on the mainland.

The outlook for the construction industry in Hawaii remains positive. Construction activity, as measured by permitting activity, peaked in 2006 and stabilized in 2007. Residential construction activity continued to decline in the first quarter of 2008. Military, industrial and commercial construction activity continue to be stabilizing factors as increased activity in those sectors helped offset the decline in residential construction. Local economists expect the overall level of construction activity to remain fairly stable for this reason. Risks to this outlook include whether reduced market liquidity will impact funding of commercial construction projects in Hawaii and whether the federal government will reduce spending on new military projects.

While the overall outlook for Hawaii is for continued moderate growth, factors such as the recent airline closures, a U.S. economic recession, inflation, and availability of credit could negatively impact the outlook for key industries such as tourism and construction. Although Hawaii unemployment remains low and well-below national averages, recent data indicates an upward trend. Hawaii unemployment at the end of March 2008 was 3.1%, compared to 2.5% at the end of March 2007. High energy costs also continue to contribute to inflation rates in Hawaii that are higher than the national inflation rate, which will in turn stress Hawaii consumers.

Management also monitors (1) oil prices because of their impact on the rates the utilities charge for electricity and the potential effect of increased electricity prices on usage, and (2) interest rates because of their potential impact on ASB’s earnings, HEI’s and HECO’s cost of capital and pension costs, and HEI’s stock price. Crude oil prices continued to push higher amid strong global demand and a weaker dollar. Crude oil traded at an average price of $97.15 per barrel during the first three months of 2008 based on West Texas Intermediate markets, compared to an average price of $64.26 per barrel for the same period last year, and is expected to trade above $100 per barrel due to continued geopolitical instability and tight refining capacity.

Overall, interest rates declined in the first three months of 2008 due to aggressive rate cutting by the Federal Open Market Committee. Lower interest rates, particularly short-term rates, and steady mortgage rates resulted in an increased bank net interest margin for the first three months of 2008. While spreads remain wide, Libor rates fell with Treasury rates which helped take pressure off bank funding and deposit costs. As of March 31, 2008, the spread between the 3-month Treasury and 3-month Libor swap rate was 1.36% compared to spreads of 1.46% and 0.31% at December 31, 2007 and March 31, 2007, respectively.

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.

“Other” segment


	Three months ended March 31						% change	Primary reason(s) for significant change
(in thousands)	2008			2007			% change	Primary reason(s) for significant change
Revenues	$	(116	)	$	1,885		NM	First quarter 2007: gain on the sale of Hoku shares of $1.4 million and leveraged lease investment income of $0.3 million First quarter 2008: unrealized losses on venture capital investments

Operating loss		(3,600	)		(2,879	)	NM	See explanation for revenues, largely offset by lower consulting and other administrative and general expenses

Net loss		(5,194	)		(5,285	)	NM	See explanation for operating loss, offset by lower interest expense

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 windfarm 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, the Company currently plans to wind up HEIII’s affairs during 2008.

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

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)	March 31, 2008				December 31, 2007
Short-term borrowings—other than bank	$	199	7	%	$	92	4	%
Long-term debt, net—other than bank		1,202	44			1,242	47
Preferred stock of subsidiaries		34	1			34	1
Common stock equity		1,304	48			1,275	48

	$	2,739	100	%	$	2,643	100	%

As of May 1, 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
Medium-term notes	BBB	Baa2

The above 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.

S&P indicated that unsupportive rate treatment that would result in further erosion of key financial parameters, especially cash flow coverage of debt, would be cause for a negative outlook and a severe slump in the state economy could also contribute to downward rating pressure.

See the electric utilities’ “Liquidity and capital resources” section below for the May 2007 downgrades by S&P of certain HECO, HELCO and MECO ratings.

In the first quarter of 2008, HEI repaid $50 million principal amount of medium-term notes with proceeds from commercial paper borrowings.

As of March 31, 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. These registrations will expire to the extent the registered securities have not been issued by November 30, 2008.

HEI utilizes short-term debt, principally 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. HEI had an average outstanding balance of commercial paper for the first three months of 2008 of $73 million and had $110 million outstanding as of March 31, 2008, with the balance of HEI’s consolidated short-term debt as of March 31, 2008 being comprised of $89 million of HECO’s commercial paper. Management believes that if HEI’s commercial paper ratings were to be downgraded, it might not be able to sell commercial paper under current market conditions.

Effective April 3, 2006, HEI entered into a revolving unsecured credit agreement establishing a line of credit facility of $100 million, with a letter of credit sub-facility, expiring on March 31, 2011, with a syndicate of eight financial institutions. Effective February 19, 2008, HEI entered into a short-term, unsecured credit agreement establishing a line of credit facility of $50 million, expiring on November 18, 2008, with William Street LLC, an affiliate of Goldman, Sachs & Co. As of May 1, 2008, the lines were undrawn. In the future, the 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.

For the first three months of 2008, net cash provided by operating activities of consolidated HEI was $26 million. Net cash used in investing activities for the same period was $30 million primarily due to net increases in loans receivable at ASB and HECO’s consolidated capital expenditures, partly offset by net decreases in investment and mortgage-related securities. Net cash provided by financing activities during this period was $1 million as a result of several factors, including net increases in short-term borrowings and retail repurchase agreements and proceeds from the issuance of common stock under HEI plans, partly offset by net decreases in deposit liabilities, other bank borrowings, long-term debt and cash overdrafts and the payment of common stock dividends.

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 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).

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 page iv under “Forward-Looking Statements.”

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

RESULTS OF OPERATIONS


	Three months ended March 31				% change	Primary reason(s) for significant change
(dollars in thousands, except per barrel amounts)	2008		2007		% change	Primary reason(s) for significant change
Revenues	$	623,889	$	447,678	39	Higher fuel oil and purchased energy fuel costs, the effects of which are generally passed on to customers ($141 million), interim rate relief ($26 million) and higher amounts of DSM costs recovered through surcharge ($3 million)
Expenses
Fuel oil		249,543		159,929	56	Higher fuel oil costs, partly offset by less KWHs generated
Purchased power		150,795		111,516	35	Higher fuel costs and more KWHs purchased
Other		172,568		163,241	6	Higher other operation and maintenance (O&M) ($5 million) and depreciation expenses ($1 million), and higher taxes, other than income taxes ($15 million), partly offset by the write-off of HELCO plant in service in 2007 ($12 million)
Operating income		50,983		12,992	292	Interim rate relief and 2007 write-off of plant in service, partly offset by higher expenses
Net income		24,585		453	5,327	Higher operating income and AFUDC and lower interest expense due primarily to lower short term borrowings and lower short term interest rates
Kilowatthour sales (millions)		2,409		2,404	—	Load growth and warmer weather, largely offset by customer conservation
Cooling degree days (Oahu)		954		845	13
Average fuel oil cost per barrel	$	93.89	$	58.19	61

Note: The electric utilities had an effective tax rate for the first quarter of 2008 of 38% and a $0.3 million tax benefit in the first quarter of 2007 due to the acceleration of the state tax credits associated with the write-off of a portion of CT-4 and CT-5 and the effect of state tax credits against a small income tax expense base.

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

Results – three months ended March 31, 2008

Operating income for the first quarter of 2008 increased 292% from the same period in 2007 due primarily to $26 million of interim rate relief granted by the PUC to HECO (2007 test year), HELCO (2006 test year) and MECO (2007 test year) in October 2007, April 2007 and December 2007, respectively 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”). Kilowatthour (KWH) sales in the first three months of 2008 were flat when compared to the same period in 2007, with only 0.2% growth, primarily due to new load growth (i.e., increase in number of customers), warmer weather and the impact of an additional leap year day in February 2008, largely offset by the impact of customer conservation efforts. Cooling degree days for Honolulu were 13% higher in the first quarter of 2008 when compared to the same period in 2007.

Other operation expenses increased 18% primarily due to higher customer service expenses, including DSM expenses that are generally passed on to customers through a surcharge ($2.6 million), administrative and general expenses ($3.6 million) and production operations expenses ($1.7 million). Pension and other postretirement benefit expenses for the electric utilities increased slightly by $0.3 million over 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”) that offset the impact of adoption of a 12.5 basis points higher discount rate assumption as of December 31, 2007 by the HEI Pension Investment Committee. Maintenance expenses decreased by 14% primarily due to the timing of expenses, including lower production maintenance expenses (primarily due to $3.0 million of costs related to a decrease in the number and scope of generating unit overhauls and lower generating station maintenance) and transmission and distribution maintenance expenses (primarily due to $0.6 million and $0.4 million of costs related to lower substation and distribution line maintenance expenses, respectively). Higher depreciation expense ($1.2 million) was attributable to additions to plant in service in 2007.

The trend of increased O&M expenses is expected to continue in 2008 as 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.

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 decreasing peak reserve margin situation, and the trend of cost increases is not likely to ease.

Renewable energy strategy

The electric utilities are taking actions intended to protect Hawaii’s island ecology and counter global warming, while continuing to provide reliable power to customers. A three-pronged strategy supports attainment of the State of Hawaii renewable portfolio standards (RPS) and the Hawaii Global Warming Solutions Act of 2007 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.

In its December 19, 2007 filing with the PUC, HECO reported a consolidated RPS of 13.8% in 2006. 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, based upon economic and technical feasibility.

In February 2007, BlueEarth Biofuels LLC (BlueEarth) announced plans for a new biodiesel refining plant to be built on the island of Maui by early 2010. The biodiesel plant will be owned by BlueEarth Maui Biofuels LLC (BlueEarth Maui), a joint venture 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 to UBC 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. In addition, MECO is negotiating a fuel purchase contract with BlueEarth Maui 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.

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 contract is subject to PUC approval. 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. HECO anticipates submitting its proposed final RFP to the PUC in May 2008.

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 of biofuels, ocean energy, battery storage, electronic shock absorber, and integration of non-firm power into the isolated island electric grids.

Energy efficiency and demand-side management 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.

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, with or without cogeneration.

In March 2000, the PUC approved a standard form contract for customer retention that allows HELCO to provide a rate option for customers who would otherwise reduce their energy use from HELCO’s system by using energy from a nonutility generator. Based on HELCO’s current rates, the standard form contract provides a 10% discount on base energy rates for qualifying “Large Power” and “General Service Demand” customers. In November 2006, HELCO entered into three-year standard form contracts with two of its hotel customers.

In 1996, the PUC issued an order instituting a proceeding to identify and examine the issues surrounding electric competition and to determine the impact of competition on the electric utility infrastructure in Hawaii. In October 2003, the PUC closed the competition proceeding and opened investigative proceedings on two specific

issues (competitive bidding and DG) to move toward a more competitive electric industry environment under cost-based regulation.

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.

The parties in the proceeding included the Consumer Advocate, HECO, HELCO, MECO, Kauai Island Utility Cooperative (KIUC) and Hawaii Renewable Energy Alliance (HREA), a renewable energy organization. The issues addressed in the proceeding included whether a competitive bidding system should be developed for acquiring or building new generation and, if so, how a fair system can be developed that “ensures that competitive benefits result from the system and ratepayers are not placed at undue risk,” what the guidelines and requirements for prospective bidders should be, and how such a system can encourage broad participation.

In December 2006, the PUC issued a decision that included a final competitive bidding framework, which became effective immediately. The final framework states, among other things, that: (1) a utility is required to use competitive bidding to acquire a future generation resource or a block of generation resources unless the PUC finds bidding to be unsuitable, (2) the determination of whether to use competitive bidding for a future generation resource or a block of generation resources will be made by the PUC during its review of the utility’s integrated resource plan (IRP), (3) an exemption from the framework is granted for cooperatively-owned utilities, (4) the framework does not apply to two pending projects (HECO’s CIP-1 and HELCO’s ST-7), MECO’s M-18 project (which went into commercial operation in October 2006), specifically identified offers to sell energy on an as-available basis or to sell firm energy and/or capacity by non-fossil fuel producers that were under review by an electric utility at the time the framework was adopted (provided that negotiations with the nonfossil fuel producers for firm capacity were completed no later than December 31, 2007), and certain other situations identified in the framework, (5) waivers from competitive bidding for certain circumstances will be considered by the PUC and granted when considered appropriate, (6) for each project that is subject to competitive bidding, the utility is required to submit a report on the cost of parallel planning upon the PUC’s request, (7) the utility is required to consider the effects on competitive bidding of not allowing bidders access to utility-owned or controlled sites, and to present reasons to the PUC for not allowing site access to bidders when the utility has not chosen to offer a site to a third party, (8) the utility is required to select an independent observer from a list approved by the PUC whenever the utility or its affiliate seeks to advance a project proposal (i.e., in competition with those offered by bidders) in response to a need that is addressed by its RFP or when the PUC otherwise determines, (9) the utility may consider its own self-bid proposals in response to generation needs identified in its RFP, (10) the evaluation of the utility’s bid should account for the possibility that the capital or running costs actually incurred, and recovered from ratepayers, over the plant’s lifetime, will vary from the levels assumed in the utility’s bid and (11) for any resource to which competitive bidding does not apply (due to waiver or exemption), the utility retains its traditional obligation to offer to purchase capacity and energy from a Qualifying Facility (QF) at avoided cost upon reasonable terms and conditions approved by the PUC. 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, and closed the competitive bidding docket.

In October 2007, the PUC issued an order opening a docket to receive filings, review approval requests, and resolve disputes, if necessary, related to a HECO proposed RFP. The order also identified HECO and the Consumer Advocate as parties to this new docket and approved HECO’s contract with the Independent Observer for the proposed RFP. In February 2008, HECO submitted a draft RFP to the PUC and to the Consumer Advocate. The draft RFP seeks proposals for the supply of up to approximately 100 MW of long-term (i.e. 20 years) renewable energy for the island of Oahu under a power purchase agreement. While the draft RFP is primarily soliciting proposals for non-firm generation, HECO will also consider proposals for firm renewable energy resources. A proposed final RFP is expected to be submitted to the PUC in May 2008.

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, 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. MECO anticipates submitting a draft RFP to the PUC and the Consumer Advocate shortly.

In December 2007, the electric utilities filed a letter in the competitive bidding docket requesting approval to update their list of non-fossil fuel purchase offers that are exempt from the competitive bidding process by including on the list three additional non-fossil fuel proposals that the electric utilities received prior to the PUC’s adoption of the competitive bidding framework. HELCO also filed a letter requesting an extension of time to conclude negotiation of a PPA with a non-fossil fuel developer on the island of Hawaii. In January 2008, the PUC issued an order that re-opened the competitive bidding docket and denied the electric utilities’ requests. In February 2008, the electric utilities filed a motion for reconsideration to update their list of offers from non-fossil fuel developers, and to continue negotiations with two developers. In April 2008, the electric utilities filed an application for approval of waivers from the competitive bidding framework for three non-fossil fuel proposals and a petition for declaratory order that the competitive bidding framework does not apply to a non-fossil fuel proposal on the island of Hawaii from PGV.

Management cannot currently predict the ultimate effect of these decision/orders on the ability of the electric 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.

With regard to DG ownership, the D&O affirmed the ability of the electric 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. In weighing the general advantages and disadvantages of allowing a utility to provide DG services on a customer’s site, the PUC found that the “disadvantages outweigh the advantages.” 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 electric 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 electric 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 electric utilities are evaluating potential DG projects. In July 2006, MECO filed an application for PUC approval of an agreement for the installation of a CHP system at a hotel site on the island of Lanai, which agreement has been approved by the PUC.

The January 2006 D&O also required the electric utilities to file tariffs, establish reliability and safety requirements for DG, establish a non-discriminatory DG interconnection policy, develop a standardized interconnection agreement to streamline the DG application review process, establish standby rates based on unbundled costs associated with providing each service (i.e., generation, distribution, transmission and ancillary services), and establish detailed affiliate requirements should the utility choose to sell DG through an affiliate. The electric 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.

Distributed generation tariff proceeding. By order dated December 28, 2006, the PUC opened a new proceeding to investigate the utilities’ proposed DG interconnection tariff modifications and standby rate tariffs. Public hearings were held in February and March 2007. In April 2007, the PUC granted intervener status to HREA, a group of hotel and resort companies, a group consisting of a CHP vendor, a hotel company and a hospital management company, a senior living community company and the United States Combined Heat and Power Association. In September 2007, all parties, except HREA, executed and filed a stipulation for approval of the electric utilities’ proposed DG interconnection tariffs. In March 2008, the parties filed a settlement agreement with the PUC that a standby service tariff agreed to by the parties should be approved, and the PUC held a hearing on the agreement. The interconnection tariffs, with modifications made in response to the PUC’s information requests, were approved in April 2008.

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 and return on rate base) for purposes of an interim rate increase does not commit the PUC to accept any such amounts in its final D&O.

As of May 1, 2008, the return on average common equity (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), 11.50% 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 10.70%.

For the 12 months ended March 31, 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 6.65%, 9.98% and 7.05%, respectively. HECO’s actual ROACE was significantly lower than its authorized ROACE primarily because of the timing of the interim rate relief for its 2007 test year rate case and increased other O&M expenses, which are expected to continue and have resulted in HECO seeking rate relief more often than in the past. MECO’s actual ROACE was significantly lower than its authorized ROACE primarily because of the timing of the interim rate relief for its 2007 test year rate case and increased other O&M expenses, which are expected to continue. The interim rate relief granted to the utilities by the PUC (see below) was based in part on increased costs of operating and maintaining their systems.

As of May 1, 2008, the return on rate base (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 March 31, 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 5.82%, 7.69% and 6.14%, 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).

HECO.

2005 test year rate case. In November 2004, HECO filed a request with the PUC to increase base rates 9.9%, or $99 million in annual base revenues, based on a 2005 test year, a 9.11% ROR and an 11.5% ROACE. The requested increase included transferring the cost of existing DSM programs from a surcharge line item on electric bills into base electricity charges. HECO also requested approval and/or modification of its existing and proposed DSM programs, and an associated utility incentive mechanism. Excluding the surcharge transfer amount, the requested net increase to customers was 7.3%, or $74 million.

In March 2005, the PUC issued a bifurcation order separating HECO’s requests for approval and/or modification of its existing and proposed DSM programs from the rate case proceeding into a new docket (EE DSM Docket). The issues for the EE DSM Docket included (1) whether, and if so, what, energy efficiency goals should be established, (2) whether the proposed and/or other DSM programs will achieve the established energy efficiency goals and be implemented in a cost-effective manner, (3) what market structures are most appropriate for providing these or other DSM programs, (4) for utility-incurred costs, what cost recovery mechanisms and cost levels are appropriate, (5) whether, and if so, what incentive mechanisms are appropriate to encourage the implementation of DSM programs and (6) which DSM programs should be approved, modified, or rejected. See “Other regulatory matters—Demand-side management programs” below for a discussion of the PUC’s D&O issued in the EE DSM Docket on February 13, 2007.

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, excluding the portion of the original rate case bifurcated into the EE DSM Docket. 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 (with tariff changes implemented on September 28, 2005). 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 June 19, 2006, the PUC issued an order in HECO’s pending 2005 test year rate case, indicating that the record in the pending case had not been developed for the purpose of addressing the factors in Act 162 (codified at Hawaii Revised Statutes §269-16(g)). Act 162, which was effective in June 2006, requires the PUC to consider certain specific factors in evaluating fuel adjustment clauses. See “Energy cost adjustment clauses” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.” The parties filed stipulations requesting the PUC not to review the Act 162 issues relating to the ECAC in the 2005 test year rate case since the case had been filed and the record in the case completed before Act 162 became law and the settlement agreement in the case included a provision allowing the ECAC to be continued.

On October 25, 2007, the PUC issued an amended proposed final D&O, authorizing an increase of 3.74%, or $45.7 million (or a net increase of $34 million or 2.7%), 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), would reverse 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 would require 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 March 31, 2008, is approximately $0.5 million, which amount has been reserved for the refund and includes an adjustment for the interest synchronization method adopted by the PUC (see below). Interest on the refund amount would continue to accrue until the amount is refunded to customers.

Under state law, if one or more of the Commissioners were not present at the evidentiary hearings in the proceeding, and the decision is adverse to a party in the proceeding, a proposed final D&O is required before a final D&O can be issued. The parties adversely affected by the proposed final D&O have ten days to file

exceptions and present arguments to the PUC, before a final D&O is rendered. HECO and the Consumer Advocate did not file exceptions or seek to present arguments with respect to the amended proposed final D&O, but the DOD filed an exception relating to the manner of determining the interest expense deduction for computing the test year income tax expense. The DOD’s position, as adopted by the PUC, did not have a material impact on the authorized rate increase.

On March 4, 2008, the PUC issued an order adopting the interest synchronization method as the mechanism for computing interest expense in this rate case and directing the parties to file stipulated revised results of operations, which reflect amounts consistent with the order and the amended proposed final D&O for the PUC’s review and approval and for subsequent incorporation into the final D&O for this rate case. On March 28, 2008, the parties filed their stipulated revised results of operations.

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. See Note 8 of HECO’s “Notes to Consolidated Financial Statements.” 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.

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. If the reduction in equity balance resulting from the AOCI charges is not restored for ratemaking purposes, the utility’s position was that 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 $69.997 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 (which is accumulated contributions to its pension plan in excess of net periodic pension cost, which amounted 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.) The parties also agreed that the PUC’s determination in the 2005 test year rate case of the issue regarding the interest expense deduction for computing the test year income tax expense (with respect to which the DOD had filed exceptions to the amended proposed final D&O in the 2005 test year rate case) would govern the resolution of that issue in the 2007 test year 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 $69.997 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. See Note 8 of HECO’s “Notes to Consolidated Financial Statements.” Consistent with the previous settlement agreement with the parties in this case, HECO is planning to file a motion with the PUC to adjust the amount of the interim increase in this proceeding 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.

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

In May 2008, HECO filed a notice with the PUC that it intends to file an application for a general rate increase based on a 2009 test year. HECO has not yet determined the amount of the rate increase it will be requesting.

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.

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.

Other regulatory matters

In addition to the items below, also see “HELCO power situation” and “East Oahu Transmission Project (EOTP)” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.”

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.

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, and are awaiting PUC approval of those goals. Thus, HELCO and MECO recorded no incentives in 2007.

In May 2007, the PUC clarified the 2007 and 2008 energy efficiency goals and the calculation of the DSM utility incentive, and granted HECO the ability to request program modifications and budget increases by letter request. In October 2007, the PUC opened a proceeding for the review of the utilities’ DSM reports and program modifications.

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. Avoided energy costs will be determined using the “resource-in / resource-out” methodology instead of the proxy method. Whether avoided energy costs are higher or lower under this methodology than the proxy method will depend on several factors, including the planned outage schedule of the generating units, the mix of resources on the particular system, the forecast demand, and, for MECO and HELCO, the relative pricing of diesel fuel and industrial fuel oil.

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 $2.9 million (before interest) of the $9.0 million of incremental IRP costs incurred by the utilities during the 1997-2006 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.

HECO’s IRP. In October 2005, HECO filed its third IRP (IRP-3), which proposes multiple solutions to meet Oahu’s future energy needs, including renewable energy resources, energy efficiency, conservation, technology (such as CHP and DG) and central station generation (including a combustion turbine generating unit in 2009 described under “HECO’s 2009 Campbell Industrial Park generating unit” ). In addition, HECO currently plans for all existing generating units to remain in operation (future environmental and other regulatory considerations permitting) beyond the 20-year IRP planning period (2006-2025). On March 7, 2007, HECO, the Consumer Advocate and an environmental organization that had been permitted to intervene, filed a stipulation with the PUC, which the PUC approved in its D&O issued on March 21, 2007. The D&O required HECO to (1) file its Evaluation Report for IRP-3 by May 31, 2007, after which the IRP-3 docket would be closed, (2) initiate the development of its IRP-4, beginning with the first Advisory Group meeting in March 2007 and (3) file its IRP-4 Plan and Action Plans by June 30, 2008, unless ordered otherwise by the PUC. On March 29, 2007, the PUC opened a new docket for the IRP-4 plan and, pursuant to the stipulation, the first Advisory Group meeting was held on March 30, 2007. Numerous Advisory Group meetings and technical sessions have been held since then. HECO filed its Evaluation Report for IRP-3 on May 31, 2007. The updated IRP-3 plan continues to include multiple solutions to meet Oahu’s future energy needs. The evaluation report expresses a strong preference for renewable energy and identifies near term, supply-side and demand-side resources that HECO is seeking to add. HECO anticipates that the firm capacity currently expected to be needed in 2022, which will be re-evaluated in IRP-4, will be met by a renewable firm capacity resource or resources. HECO is also considering conversion of its generating units to biofuels or biofuel blends.

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 “HELCO power situation” 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. The parties to the IRP-3 proceedings included HELCO and the Consumer Advocate. An environmental organization and a renewable energy organization were previously parties to the IRP-3 proceeding, but later withdrew. On November 16, 2007, HELCO and the Consumer Advocate filed a stipulated agreement which recommended that the PUC approve HELCO’s IRP-3. In the stipulation, HELCO agreed to submit evaluation reports by March 31, 2009 and March 31, 2010, make various improvements to the IRP process, and submit its IRP-4 by March 31, 2011. On January 24, 2008, the PUC issued its D&O approving HELCO’s IRP-3 and the stipulated agreement, except that the PUC required HELCO to file its IRP-4 no later than 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. The plan also includes approximately 2 MW of additional generation through the year 2026 on each of the islands of Lanai and Molokai. On September 21, 2007, the parties to the IRP-3 proceedings, which includes MECO and the Consumer Advocate, filed a stipulated agreement in which they do not request a hearing, they recommend the PUC approve MECO’s IRP-3, MECO agrees to submit evaluation reports by December 31, 2008 and December 31, 2009, MECO agrees to make various improvements to the IRP process and submit its IRP-4 by December 31, 2010, and allowance is made for disposition of this proceeding.

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 not less than two years’ prior written notice by either party. 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. As a result of this agreement with HC&S, for planning purposes it appears that the timing of the need for the second 20 MW block of firm capacity on Maui can be deferred from 2013 to the 2015 timeframe. However, identifying the timing of the need for the second 20 MW block of firm capacity in the 2015 timeframe does not reduce MECO’s need to proceed expeditiously with the issuance of an RFP for this second capacity increment, given the multitude of factors that can impact the timing of system firm capacity needs and the potentially long lead time to acquire such resources.

In March 2008, MECO held an Advisory Group meeting to discuss its fourth IRP.

HECO’s 2009 Campbell Industrial Park (CIP) generating unit. HECO plans to build a new 110 MW simple cycle combustion turbine (CT) generating unit at CIP and 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, but with the capability of using diesel or naphtha. 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.

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).

Costs for the Project (exclusive of the costs of the community benefit measures described below) are currently estimated at $164 million. As of March 31, 2008, Project costs for planning, engineering, permitting, materials, land and AFUDC amounted to $30 million.

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.

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. HECO is currently conducting its IRP-4 process, which includes an assessment of the firm capacity resource additions needed to address expected continuing reserve capacity shortfall.

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.

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

October 2006 outages. On Sunday, October 15, 2006, shortly after 7 a.m., two earthquakes centered on the island of Hawaii with magnitudes of 6.7 and 6.0 triggered power outages throughout most of the state and disrupted air traffic on all major islands. On Oahu, following the impact of the earthquakes, a series of protective actions and automatic systems operated to successively shut down all generators to protect them from potential damage. As a result, no significant damage to any of HECO’s generators, or to its transmission and distribution systems, occurred. Following the island-wide outage, HECO restored power to customers in a careful, methodical manner to further protect its system, and as a result power was restored to over 99% of its customers within a period of time ranging from approximately 4¹/2 to 18 hours. Management believes the shutdown and methodical restoration of power were necessary to prevent severe damage to HECO’s generating equipment and power grid and to avoid a more prolonged blackout. HELCO’s and MECO’s smaller electric systems also experienced sustained outages from the earthquakes; however, their systems were, for the most part, back online by mid to late afternoon.

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

it clear that in addition to any investigation it undertakes, it will cooperate fully with any other reviews conducted by its regulators.

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

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

Intra-governmental wheeling of electricity. In June 2007, the PUC initiated an investigation 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), two environmental groups, 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 November 2008, with a formal process to commence thereafter.

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 “Environmental regulation” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.”

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. The 2004 Hawaii Legislature amended an existing renewable portfolio standards (RPS) law to require 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 the required renewables 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 was further amended in 2006 to provide 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 amendment also added provisions 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, which may include, but is not limited to, performance-based ratemaking, 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.

On January 11, 2007, the PUC opened a new docket (RPS Docket) to examine Hawaii’s amended RPS law, to establish the appropriate penalties and to determine circumstances under which penalties should be levied. The PUC indicated that the 2006 amendment to the RPS law that added provisions for penalties effectively gives utilities incentive to comply with RPS and therefore the PUC would no longer complete the rulemaking process initiated in November 2004, but would instead proceed by way of this RPS Docket to handle any issues related to the utilities meeting RPS. The parties to the proceeding include the electric utilities, the Consumer Advocate, an environmental organization and HREA. The PUC set forth the issues for the proceeding to be (1) the appropriate penalty framework to establish under the RPS law for failure to meet the RPS, (2) the appropriate utility ratemaking structure to establish and include in the framework to provide incentives that encourage electric utilities to use cost effective renewable energy resources while allowing for deviations from the standards in the event the standards cannot be met in a cost-effective manner, or as a result of circumstances beyond the control of the electric utility that could not have been reasonably anticipated or ameliorated and (3) whether the framework should include a provision that provides incentives to encourage utilities to exceed the RPS or to meet their RPS ahead of time or both. In July 2007, HECO, HELCO and MECO proposed a Renewable Energy Infrastructure Program, including a surcharge mechanism, to encourage the funding of renewable energy infrastructure projects.

In October 2007, all but one of the parties executed and filed a stipulation for an RPS framework. The proposed Renewable Energy Infrastructure Program 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.

In December 2007, the PUC issued a decision and order approving the stipulated framework, with modifications, but deferred the incentive framework, including the proposed renewable energy infrastructure surcharge, to a new generic docket. The PUC also directed the parties to file supplemental briefs in the RPS Docket 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. The parties for the new docket are the same as the parties for the RPS Docket. Public hearings are scheduled to take place in May 2008.

Management cannot predict the outcome of this process.

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). The law provides a cap of 0.5% of the electric utility’s peak demand on the total generating capacity produced by eligible customer-generators. The 2004 Legislature amended the net energy metering law by expanding the definition of “eligible customer generator” to include government entities, increasing the maximum size of eligible net metered systems from 10 kilowatts (kw) to 50 kw and limiting exemptions from additional requirements for systems meeting safety and performance standards to systems of 10 kw or less.

In 2005, the Legislature again 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 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 September 2007, a stipulated agreement was 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. In March 2008, the PUC approved the electric utilities’ September 2007 stipulated agreement and 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 Legislature again amended the net energy metering law 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.

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

Non-fossil fuel purchased power contracts. The 2006 Hawaii State Legislature passed a measure which 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 of the 2007 Hawaii State Legislature became law and 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. 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.

Renewable energy. The 2007 Hawaii State Legislature passed a measure stating 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.

The 2008 Hawaii State Legislature passed a measure to promote and encourage the use of solar thermal energy. This measure would 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 would establish standards for quality and performance of such systems. The 2008 Hawaii Legislature also passed a measure intended to facilitate the permitting of larger (200 MW or greater) renewable energy projects.

Biofuels. The 2007 Hawaii State Legislature passed a measure that has the stated purpose of encouraging further production and use of biofuels in Hawaii, establishes that biofuel processing facilities in Hawaii are a permitted use in designated agricultural districts and establishes a program with the Hawaii Department of Agriculture to encourage the production in Hawaii of energy feedstock (i.e., raw materials for biofuels).

The 2008 Hawaii State Legislature passed a measure 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.

At this time, it is not possible to predict with certainty the impact of any legislation or proposed legislation.

Other developments

Advanced Meter Infrastructure (AMI). HECO continues 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 6,500 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.

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

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)	March 31, 2008				December 31, 2007
Short-term borrowings	$	89	4	%	$	29	1	%
Long-term debt		895	42			885	43
Preferred stock		34	2			34	2
Common stock equity		1,121	52			1,110	54

	$	2,139	100	%	$	2,058	100	%

As of May 1, 2008, the S&P and Moody’s ratings of HECO securities were as follows:


	S&P	Moody’s
Commercial paper	A-2	P-2
Revenue bonds (principal amount noted in parentheses, senior unsecured, insured as follows):
Ambac Assurance Corporation ($0.2 billion)	AAA	Aaa
Financial Guaranty Insurance Company ($0.3 billion)	BBB*	Baa1*
MBIA Insurance Corporation ($0.3 billion)	AAA	Aaa
XL Capital Assurance Inc. ($0.1 billion)	A-	A3
HECO-obligated preferred securities of trust subsidiary	BB+	Baa2
Cumulative preferred stock (selected series)	Not rated	Baa3

Financial Guaranty Insurance Company’s (FGIC’s) current financial strength rating by S&P is BB and its insurance financial strength rating by Moody’s is Baa3. The revenue bonds insured by FGIC 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.

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 2007, S&P lowered the long-term corporate credit and unsecured debt ratings on HECO, HELCO and MECO to BBB from BBB+, lowered the rating on HECO-obligated preferred securities of trust subsidiary to BB+ from BBB-, and lifted HECO’s outlook from “negative” to “stable”. 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).” S&P stated that the downgrade “is the result of sustained weak bondholder protection parameters compounded by the financial pressure that continuous need for regulatory relief, driven by heightened capital expenditure requirements, is creating for the next few years.”

S&P also ranks business profiles from “1” (excellent) to “10” (vulnerable), and did not change HECO’s business profile rank of “5”.

In September 2007, S&P maintained HECO’s ratings and business profile rank of “5” and indicated that unsupportive rate treatment that would result in the erosion of key financial parameters, especially cash flow coverage of debt, and a slump in the state economy could lead to downward rating pressure.

In December 2007, 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% (16% as of September 30, 2007-latest reported by Moody’s) or Adjusted Cash Flow to Adjusted Interest declined to less than 3.6x (3.8x as of September 30, 2007-latest reported by Moody’s) for an extended period, the rating could be lowered.

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. The intercompany borrowings among the utilities, but not the borrowings from HEI, are eliminated in the consolidation of HECO’s financial statements. As of March 31, 2008, HECO had $0.5 million of short-term borrowings from MECO and HELCO had $43 million of short-term borrowings from HECO. HECO had an average outstanding balance of commercial paper for the first three months of 2008 of $53 million and had $89 million of commercial paper outstanding as of March 31, 2008. Management believes that if HECO’s commercial paper ratings were to be downgraded, it may be more difficult and expensive for HECO to sell commercial paper under current market conditions.

Effective April 3, 2006, HECO entered into a revolving unsecured credit agreement establishing a line of credit facility of $175 million with a syndicate of eight financial institutions. The agreement expires on March 31, 2011. As of May 1, 2008, the line was undrawn. 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.

Revenue bonds are issued by the Department of Budget and Finance of the State of Hawaii for the benefit 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 XL Capital Assurance, Inc. (XLCA). 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 FGIC and XLCA were downgraded by S&P and Moody’s resulting in a downgrade of the bond ratings of certain of the bonds as shown in the table above. S&P and/or Moody’s ratings of Ambac, FGIC, MBIA and XLCA are reported to be on negative outlook and/or watch and/or review for potential downgrade.

Operating activities provided $7 million in net cash during the first three months of 2008. Investing activities during the same period used net cash of $44 million primarily for capital expenditures, net of contributions in aid of construction. Financing activities for the same period provided net cash of $47 million, primarily due to a $60 million net increase in short-term borrowings and drawdown of $10 million in SPRBs, partly offset by the payment of $14 million of common and preferred dividends and $9 million decrease in cash overdraft.

SPRBs of up to $20 million (for HELCO) and up to $400 million ($260 million for HECO, $115 million for HELCO and $25 million for MECO) may be issued by the Department of Budget and Finance of the State of Hawaii under 2005 and 2007 legislative authorizations prior to the end of June 30, 2010 and June 30, 2012, respectively, to finance the electric utilities’ capital improvement projects.

The PUC must approve issuances, if any, of equity and long-term debt securities by HECO, HELCO and MECO.

BANK

RESULTS OF OPERATIONS


	Three months ended March 31				% change	Primary reason(s) for significant change
(in thousands)	2008		2007		% change	Primary reason(s) for significant change
Revenues	$	105,844	$	104,460	1	Higher noninterest income

Operating income		23,363		18,428	27	Higher net interest income, higher noninterest income, and lower noninterest expense, partly offset by higher provision for loan losses

Net income		14,576		11,596	26	Higher operating income

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 March 31, 2008, ASB’s loan portfolio mix, net, consisted of 74% residential loans, 12% commercial loans, 7% commercial real estate loans and 7% 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. 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 March 31, 2008 and December 31, 2007, ASB’s costing liabilities consisted of 71% deposits and 29% other borrowings. 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 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 March 31, 2008, 73% of ASB’s portfolio is held in debentures or mortgage-related securities issued by government-sponsored entities. The remaining 27% of the portfolio is composed of mortgage-related securities issued by private issuers (26% are rated AAA and 1% 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 either been downgraded or are on watch. 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.

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 or an “other-than-temporary” impairment in the value of the securities. As of March 31, 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.”

The following table sets forth average balances, interest and dividend income, interest expense and weighted-average yields earned and rates paid, for certain categories of earning assets and costing liabilities for the three months ended March 31, 2008 and 2007.


	Three months ended March 31
	2008		2007		Change
($ in millions)
Loans receivable
Average balances ¹	$	4,136	$	3,805	331
Interest income ²		63		60	3
Weighted-average yield (%)		6.14		6.36	(0.22	)
Investment and mortgage-related securities
Average balances	$	2,128	$	2,382	(254	)
Interest income		24		27	(3	)
Weighted-average yield (%)		4.49		4.48	0.01
Other investments ³
Average balances	$	137	$	204	(67	)
Interest and dividend income		1		1	—
Weighted-average yield (%)		1.62		2.87	(1.25	)
Total earning assets
Average balances	$	6,401	$	6,391	10
Interest and dividend income		88		88	—
Weighted-average yield (%)		5.50		5.55	(0.05	)
Deposit liabilities
Average balances	$	4,330	$	4,532	(202	)
Interest expense		18		21	(3	)
Weighted-average rate (%)		1.69		1.86	(0.17	)
Borrowings
Average balances	$	1,806	$	1,636	170
Interest expense		19		18	1
Weighted-average rate (%)		4.25		4.55	(0.30	)
Total costing liabilities
Average balances	$	6,136	$	6,168	(32	)
Interest expense		37		39	(2	)
Weighted-average rate (%)		2.44		2.57	(0.13	)
Net average balance	$	265	$	223	42
Net interest income		51		49	2
Interest rate spread (%)		3.06		2.98	0.08
Net interest margin (%) ⁴		3.16		3.07	0.09

¹	Includes nonaccrual loans.

²	Includes loan fees of $1.1 million and $1.2 million for three months ended March 31, 2008 and 2007, respectively, together with interest accrued prior to suspension of interest accrual on nonaccrual loans.

³	Includes federal funds sold and interest bearing deposits and stock in the FHLB of Seattle ($98 million as of March 31, 2008).

⁴	Defined as net interest income as a percentage of average earning assets.

Results – three months ended March 31, 2008

Net interest income before provision for loan losses for three months ended March 31, 2008 increased by $1.2 million, or 3%, when compared to the same period in 2007. Net interest margin increased from 3.07% in the first quarter of 2007 to 3.16% in the first quarter of 2008 as lower funding costs and higher balances on loans were partially offset by lower yields on loans and lower balances of investment and mortgage-related securities. The increase in the average loan portfolio balance was due, in part, to continued growth in the residential loan portfolio as a result of the continued strength in the Hawaii economy and real estate market. The decrease in the average investment and mortgage-related securities portfolios was due to the use of proceeds from repayments in the portfolio to fund loans. Average deposit balances decreased by $202 million compared to the first quarter of 2007, and decreased by $17 million compared to the last quarter of 2007. ASB experienced outflows throughout 2007 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 first quarter of 2008, ASB recorded a provision for losses of $0.9 million due to loan growth as well as the reclassification of certain commercial loans. During the first quarter of 2007, the need to provide for loan losses as a result of additional loan growth was fully offset by the release of reserves on existing loans due to strong asset quality.


	Three months ended March 31						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		900			—			5,700
Less: net charge-offs		483			708			6,717

Allowance for loan losses, end of period	$	30,628		$	30,520		$	30,211

Ratio of allowance for loan losses, end of period, to average loans outstanding		0.74	%		0.80	%		0.78	%

Ratio of net charge-offs during the period to average loans outstanding		0.05	%		0.07	%		0.17	%

Nonaccrual loans		7,451			4,470			3,195

Nonperforming assets to total assets		0.11	%		0.06	%		0.05	%

First quarter of 2008 noninterest income increased by $1.9 million, or 12%, when compared to the first quarter of 2007, primarily due to a gain on sale of stock in a membership organization and increases in deposit fees and card fees.

Noninterest expense for the three months ended March 31, 2008 decreased by $2.7 million, or 6%, when compared to the first quarter of 2007, primarily due to lower legal and other litigation expenses.

FHLB of Seattle business and capital plan

In December 2004, the FHLB of Seattle signed an agreement with its regulator, the Federal Housing Finance Board (Finance Board), to adopt a business and capital plan to strengthen its risk management, capital structure and governance. At the time and as of March 31, 2008, ASB had an investment in FHLB of Seattle stock of $98 million. In January 2007, the FHLB of Seattle announced that the Finance Board had terminated its agreement with the FHLB of Seattle, attributing the termination to its full compliance with the terms of the agreement and significant progress the FHLB of Seattle has made in implementing its business and capital management plan. ASB received cash dividends of $98,000 in February 2007, $147,000 in each of May 2007 and August 2007, $196,000 in November 2007 and $244,000 in February 2008.

FINANCIAL CONDITION

Liquidity and capital resources


(in millions)	March 31, 2008		December 31, 2007		% change
Total assets	$	6,844	$	6,861	—
Available-for-sale investment and mortgage-related securities		2,086		2,141	(3	)
Investment in stock of FHLB of Seattle		98		98	—
Loans receivable, net		4,154		4,101	1
Deposit liabilities		4,330		4,347	—
Other bank borrowings		1,789		1,811	(1	)

As of March 31, 2008, ASB was the third largest financial institution in Hawaii based on assets of $6.8 billion.

In March 2007, Moody’s raised ASB’s counterparty credit rating to A3 from Baa3 and acknowledged ASB’s high capital ratios, excellent asset quality indicators and prudent liquidity posture. In April 2007, S&P raised ASB’s long-term/short-term counterparty credit ratings to BBB/A-2 from BBB-/A-3 and acknowledged the improvement in ASB’s interest rate risk and funding profiles from its community banking strategy, its still modest credit risk profile and its solid capital base. These 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 March 31, 2008, ASB’s unused FHLB borrowing capacity was approximately $1.2 billion. As of March 31, 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 three months of 2008, net cash provided by ASB’s operating activities was $33 million. Net cash provided during the same period by ASB’s investing activities was $14 million, primarily due to repayments of investment and mortgage-related securities of $133 million, partly offset by a net increase in loans receivable of $52 million and purchases of investment and mortgage-related securities of $66 million. Net cash used in financing activities during this period was $61 million, primarily due to net decreases in Federal Home Loan Bank advances, deposit liabilities, and escrow deposits of $64 million, $17 million, and $5 million, respectively, and the payment of $17 million in common stock dividends, partly offset by net increases in securities sold under agreements to repurchase and retail repurchase agreements of $28 million and $14 million, respectively.

As of March 31, 2008, ASB was well-capitalized (minimum ratio requirements noted in parentheses) with a leverage ratio of 7.8% (5.0%), a Tier-1 risk-based capital ratio of 13.5% (6.0%) and a total risk-based capital ratio of 14.3% (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 March 31, 2008 and December 31, 2007 constitute “forward-looking statements” and were as follows:


	March 31, 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	(0.1	)%	5.00	%	(406	)	(2.2	)%	6.97	%	(334	)
+200	0.3		6.51		(255	)	(0.9	)	8.27		(204	)
+100	0.5		7.97		(109	)	(0.2	)	9.46		(85	)
Base	—		9.06		—		—		10.31		—
-100	(1.6	)	9.17		11		(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 March 31, 2008, the -200 and -300 bp scenarios were not performed because they would have resulted in negative Treasury interest rates.

ASB’s net interest income (NII) sensitivity as of March 31, 2008 is slightly more asset sensitive in rising rate scenarios than it was as of December 31, 2007. This change is largely due to the lower level of interest rates on March 31, 2008 compared to December 31, 2007. In the first quarter of 2008, short term interest rates fell approximately 200 bp. In the +100 and +200 bp scenarios, the increase in interest income is greater than the increase in interest expense and the net result is a slight improvement in the 12-month estimate of NII compared to the base case. In the +300 bp scenario, the increase in the cost of the liabilities exceeds the increase in interest income. In the -100 bp scenario, the decline in NII is greater than as of December 31, 2007 primarily because the decline in interest expense is limited by the low level of interest rates, which limits the amount deposit rates can decline.

The decline in ASB’s base net present value (NPV) ratio as of March 31, 2008 compared to December 31, 2007 is primarily due to the decline in interest rates. This change is consistent with the NPV ratio profile as of December 31, 2007, which estimates that the NPV ratio would decline about 64 bp in the -200 bp scenario. Some of the difference between the estimated change and the actual change can be attributed to the fact that the yield curve did not change in a parallel manner, as well changes in pricing spreads and volatility. The decline in ASB’s NPV ratio was not the result of significant changes in ASB’s balance sheet mix nor was it the result of deterioration in the credit quality of ASB’s investments or loans.

ASB’s NPV ratio sensitivity measure as of March 31, 2008 is slightly more sensitive in rising rate scenarios when compared to the NPV ratio sensitivity measure as of December 31, 2007. This is 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 first 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 March 31, 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 March 31, 2008. Based on their evaluations, as of March 31, 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 first 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 March 31, 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

T. Michael May, HECO Chief Executive Officer, and Tayne S. Y. Sekimura, HECO Chief Financial Officer, have evaluated the disclosure controls and procedures of HECO as of March 31, 2008. Based on their evaluations, as of March 31, 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 II. Item 1. Legal Proceedings”) 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 page iv herein.

Item 5. Other Information

A. Ratio of earnings to fixed charges.


	Three months ended March 31		Years ended December 31,
	2008	2007	2007	2006	2005	2004	2003
HEI and Subsidiaries
Excluding interest on ASB deposits	2.31	1.22	1.78	2.08	2.31	2.32	2.11
Including interest on ASB deposits	1.90	1.14	1.52	1.73	1.98	2.00	1.84
HECO and Subsidiaries	3.77	.99	2.43	3.14	3.23	3.49	3.36

See HEI Exhibit 12.1 and HECO Exhibit 12.2.

B. News release.

On May 5, 2008, HEI issued a news release, “Hawaiian Electric Industries, Inc. Reports First Quarter 2008 Earnings.” See HEI Exhibit 99.

Item 6. Exhibits


HEI Exhibit 12.1		Hawaiian Electric Industries, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, three months ended March 31, 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 Acting 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 Acting 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 May 5, 2008, “Hawaiian Electric Industries, Inc. Reports First Quarter 2008 Earnings”

HECO Exhibit 12.2		Hawaiian Electric Company, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, three months ended March 31, 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 T. Michael May (HECO Chief 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 T. Michael May (HECO Chief 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/ T. Michael May
	Constance H. Lau		T. Michael May
	President and Chief Executive Officer		President and Chief Executive Officer
	(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: May 5, 2008		Date: May 5, 2008